World Energy Outlook 2010

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World Energy Outlo ok

2010

World Energy Outlook

2010

The world appears to be emerging from the worst economic crisis in decades. Many countries have made pledges under the Copenhagen Accord to reduce greenhouse-gas emissions. Commitments have also been made by the G-20 and APEC to phase out inefficient fossil-fuel subsidies. Are we, at last, on the path to a secure, reliable and environmentally sustainable energy system? Updated projections of energy demand, production, trade and investment, fuel by fuel and region by region to 2035 are provided in the 2010 edition of the World Energy Outlook (WEO). It includes, for the first time, a new scenario that anticipates future actions by governments to meet the commitments they have made to tackle climate change and growing energy insecurity. WEO-2010 shows: n

hat more must be done and spent to achieve the goal of the Copenhagen Accord to w limit the global temperature increase to 2°C and how these actions would impact on oil markets;

the trends in Caspian energy markets and the implications for global energy supply;

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the prospects for unconventional oil; and

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how to give the entire global population access to modern energy services.

With extensive data, projections and analysis, WEO-2010 provides invaluable insights into how the energy system could evolve over the next quarter of a century. The book is essential reading for anyone with a stake in the energy sector.

€150 (61 2010 15 1P1) ISBN: 978 92 64 08624 1

World Energy Outlo ok

2010

INTERNATIONAL ENERGY AGENCY The International Energy Agency (IEA), an autonomous agency, was established in November 1974. Its mandate is two-fold: to promote energy security amongst its member countries through collective response to physical disruptions in oil supply and to advise member countries on sound energy policy. The IEA carries out a comprehensive programme of energy co-operation among 28 advanced economies, each of which is obliged to hold oil stocks equivalent to 90 days of its net imports. The Agency aims to: n Secure member countries’ access to reliable and ample supplies of all forms of energy; in particular, through maintaining effective emergency response capabilities in case of oil supply disruptions. n Promote sustainable energy policies that spur economic growth and environmental protection in a global context – particularly in terms of reducing greenhouse-gas emissions that contribute to climate change. n Improve transparency of international markets through collection and analysis of energy data. n Support global collaboration on energy technology to secure future energy supplies and mitigate their environmental impact, including through improved energy efﬁciency and development and deployment of low-carbon technologies. n Find solutions to global energy challenges through engagement and dialogue with non-member countries, industry, international organisations and other stakeholders.

Three of the thousands of numbers in the World Energy Outlook 2010, despite their disparity, are worth putting alongside each other: z $312 billion — the cost of consumption subsidies to fossil fuels in 2009. z $57 billion — the cost of support given to renewable energy in 2009. z $36 billion per year — the cost of ending global energy poverty by 2030. Adding under two percent to electricity tariffs in the OECD would raise enough money to bring electricity to the entire global population within twenty years; while, in the past year, the prospective cost of the additional global energy investment to 2035 to curb greenhouse-gas emissions has risen by $1 trillion because of the caution of the commitments made at Copenhagen. My chief economist, Fatih Birol, and his team have again met our high expectations. We have new projections, fuel by fuel, extending now to 2035; a special focus on renewable energy; a stock-taking on energy and climate change in the aftermath of Copenhagen; a look at the cost of achieving universal access to electricity and clean cooking fuels; detailed information on the energy demand and resources of the countries in the Caspian region; and insights into the scale of fossil-fuel subsidies and the implications of phasing them out. The basis of our projections this year has changed. The old Reference Scenario is dead (though reborn as the Current Policies Scenario). The centrepiece of our presentation is now the New Policies Scenario. This departs from our previous practice of building our projections only on the measures governments had already taken.

Predicting what governments might do is a hazardous business. We have gone no further than to take governments at their word, interpreting the intentions they have declared into implementing measures and projecting the future on that basis. More commitments and more policies will surely follow. We have not attempted to guess what they might be; but the 450 Scenario remains as a measure of how much more must be done to realise a sustainable future and how it could be done. One point is certain. The centre of gravity of global energy demand growth now lies in the developing world, especially in China and India. But uncertainties abound. Is our emergence from the financial crisis of 2008-2009 a solid enough basis for our assumptions about economic growth? Will China sustain and intensify the four-fold improvement in energy intensity it has achieved in the last thirty years? Would a three-fold increase in oil revenues in real terms satisfy OPEC producers in a world committed to keep the global temperature rise below 2°Celsius? What will be the upshot of the controversy about the sustainablility of biofuels production? Will carbon capture and storage become a commercially available technology within a decade? Foreword

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We cannot know. But, with the invaluable financial and analytical support of our member countries and others who rely on the WEO, we can and do ensure, through this new edition of the WEO, that responsible and rigorous information is available to help decision-makers discharge their responsibilities to shape the energy future.

This publication has been produced under the authority of the Executive Director of the International Energy Agency. The views expressed do not necessarily reflect the views or policies of individual IEA member countries.

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World Energy Outlook 2010

ACKNOWLEDGEMENTS

This study was prepared by the Office of the Chief Economist (OCE) of the International Energy Agency in co-operation with other offices of the Agency. It was designed and directed by Fatih Birol, Chief Economist of the IEA. Laura Cozzi and Marco Baroni co-ordinated the analysis of climate policy and modelling; Trevor Morgan co-ordinated the analysis of oil and natural gas and the Caspian outlook; Amos Bromhead co-ordinated the analysis of fossil-fuel subsidies. Maria Argiri led the work on renewables, John Corben and Paweł Olejarnik (oil, gas and coal supply), Christian Besson (unconventional oil), Alessandro Blasi (Caspian and oil), Raffaella Centurelli (energy poverty and modelling), Michael-Xiaobao Chen (fossil-fuel subsidies and China), Michel D’Ausilio (power sector and renewables), Dafydd Elis (power sector and renewables), Matthew Frank (fossil-fuel subsidies and power sector), Tim Gould (Caspian and oil), Timur Gül (transport and modelling), Kate Kumaria (climate policy), Qiang Liu (China), Bertrand Magné (climate policy and modelling), Teresa Malyshev (energy poverty), Timur Topalgoekceli (oil), David Wilkinson (power sector and modelling) and Akira Yanagisawa (fossil-fuel subsidies and modelling). Sandra Mooney provided essential support. For more information on the OCE team, please see www.worldenergyoutlook.org. Robert Priddle carried editorial responsibility. The study benefited from input provided by IEA experts in different offices. Paolo Frankl, Milou Beerepoot, Hugo Chandler and several other colleagues of the Renewable Energy Division made valuable contributions to the renewable energy analysis. Ian Cronshaw provide very helpful input to the gas and power sector analysis. Other IEA colleagues who provided input to different parts of the book include, Jane Barbière, Madeleine Barry, Ulrich Benterbusch, Rick Bradley, Aad van Bohemen, Pierpaolo Cazzola, Anne-Sophie Corbeau, Bo Diczfalusy, David Elzinga, Lew Fulton, David Fyfe, Rebecca Gaghen, Jean-Yves Garnier, Grayson Heffner, Christina Hood, Didier Houssin, Brian Ricketts, Bertrand Sadin, Maria Sicilia, Sylvie Stephan and Cecilia Tam. Experts from a number of directorates of the OECD also made valuable contributions to the report, particularly Helen Mountford, Ronald Steenblik, Jean-Marc Burniaux, Jean Château and Dambudzo Muzenda. Thanks also go to Debra Justus for proofreading the text.

The work could not have been achieved without the substantial support and co-operation provided by many government bodies, international organisations and energy companies worldwide, notably: Department of Energy, United States; Enel; Energy Research Institute, China; Foreign Affairs and International Trade, Canada; Foreign and Commonwealth Office, United Kingdom; HM Treasury, United Kingdom; IEA Coal Industry Advisory Board (CIAB); Intergovermental Panel on Climate Change (IPCC); Ministry of Economic Affairs, The Netherlands; Ministry of Economy, Trade and Industry, Japan; Ministry of Foreign Affairs, Norway; Ministry of the Economy, Poland; National Renewable Energy Acknowledgements

Many international experts provided input, commented on the underlying analytical work and reviewed early drafts of each chapter. Their comments and suggestions were of great value. They include: Asset Abdualiyev

The individuals and organisations that contributed to this study are not responsible for any opinions or judgements contained in this study. All errors and omissions are solely the responsibility of the IEA.

Energy poverty Highlights Introduction Energy and development Energy and the Millennium Development Goals The Universal Modern Energy Access Case Access to electricity Access to clean cooking facilities Investment needs in the Universal Modern Energy Access Case Financing for universal modern energy access Monitoring progress and the Energy Development Index Other potential indicators Policy implications

Projections by scenario Investment and finance Recent trends in investment Who invests: the structure of the renewables industry Outlook for investment Costs of renewables The cost of government support mechanisms Research and development Integration costs of variable renewables Benefits of renewables Characteristics of renewable energy Hydropower Biomass Solar Wind power Geothermal energy Marine power

278 283 283 289 292 295 295 296 297 297 299 299 299 299 300 300 301

Renewables for electricity Highlights Outlook for renewables-based electricity generation Recent trends and prospects to 2035 Renewables-based electricity generating costs Investment needs Government support for renewables Recent policy developments Quantifying government support for renewables Impact of government support on electricity prices Network integration of variable renewables Overview Integration costs Dealing with the variability of renewables Special focus: Offshore wind power Investment Technology Special focus: Renewables in the Middle East and North Africa Domestic policies and initiatives Outlook Large-scale development of renewables in MENA The economics of concentrating solar power

Modern renewables Renewable energy technologies for heat Biomass Solar Geothermal Policies to support renewables for heat Renewable energy for cooling

344 350 350 350 351 352 354

Renewables for transport Highlights Overview Biofuels consumption trends Government policies to support biofuels United States European Union Brazil Quantifying the value of government support to biofuels Biofuels technologies Conventional biofuels Advanced biofuels Biofuels emissions Biofuels costs

Energy and the ultimate climate change target Highlights Introduction The 450 trajectory in the new global context Assumptions and methodology Total greenhouse-gas emissions and their energy-related component All gases Energy-related CO2 emissions Where and how are the savings to be made? Abatement by region Selecting the measures Implications for energy demand The cost of achieving the 450 Scenario The cost of Copenhagen Macroeconomic costs Implications for spending on low-carbon energy technologies Benefits Reduced local pollution Avoided mitigation and adaptation costs

Chapter 1. Context and analytical framework 1.1 Population by major region 1.2 Average IEA crude oil import price by scenario 1.3 Ratio of average natural gas and coal import prices to crude oil in the New Policies Scenario Chapter 2. Energy projections to 2035 2.1 World primary energy demand by scenario Shares of energy sources in world primary demand by scenario 2.2 2.3 Change in global primary energy intensity by scenario 2.4 World primary energy demand by fuel in the New Policies Scenario 2.5 World primary energy demand by region in the New Policies Scenario 2.6 Incremental primary energy demand by fuel and region in the New Policies Scenario, 2008-2035 2.7 Incremental energy demand by sector and region in the New Policies Scenario, 2008-2035 2.8 Per-capita primary energy demand by region as a percentage of 2008 world average in the New Policies Scenario 2.9 Energy intensity in selected countries and regions in the New Policies Scenario 2.10 World incremental fossil-fuel production in the New Policies Scenario, 2008-2035 2.11 Expenditure on net imports of oil and gas as a share of real GDP in the New Policies Scenario 2.12 Cumulative investment in energy-supply infrastructure by region and fuel in the New Policies Scenario, 2010-2035 2.13 World energy-related CO2 emissions by fuel in the New Policies Scenario 2.14 Per-capita energy-related CO2 emissions by region as a percentage of 2008 world average in the New Policies Scenario 2.15 Total primary and per-capita energy demand in China and the OECD in the New Policies Scenario 2.16 China’s share of the projected net global increase for selected indicators 26

Chapter 3: Oil market outlook 3.1 World primary oil demand by scenario Annual change in global real GDP and primary oil demand in the New 3.2 Policies Scenario 3.3 Change in primary oil demand by sector and region in the New Policies Scenario, 2009-2035 3.4 Transport oil consumption by type in the New Policies Scenario 3.5 Passenger light-duty vehicle fleet and ownership rates by region in the New Policies Scenario 3.6 Passenger light-duty vehicle sales by type in the New Policies Scenario 3.7 Average fuel economy of new passenger light-duty vehicle sales by region in the New Policies Scenario 3.8 Road transportation per-capita oil consumption by region in the New Policies Scenario 3.9 Comparative running cost of conventional and hybrid light-duty vehicles in the United States 3.10 Payback period for hybrid light-duty vehicles in selected countries at current costs 3.11 Oil savings from use of natural gas in road transport by region in the New Policies Scenario 3.12 Aviation oil consumption by region in the New Policies Scenario 3.13 Proven oil reserves in the top 15 countries, end-2009 3.14 Conventional oil discoveries and production worldwide 3.15 Proven reserves, recoverable resources and production of conventional oil by region in the New Policies Scenario 3.16 World crude oil production by scenario 3.17 Change in world oil and biofuels production by scenario, 2009-2035 3.18 World oil production by source in the New Policies Scenario 3.19 World oil production by type in the New Policies Scenario 3.20 Sensitivity of non-OPEC crude oil production to ultimately recoverable resources 3.21 World crude oil production by physiographical location in the New Policies Scenario 3.22 Drivers of natural gas liquids production 3.23 World oil production by quality in the New Policies Scenario 3.24 World oil production by type of company in the New Policies Scenario 3.25 Worldwide upstream oil and gas capital spending by type of company 3.26 IEA Upstream Investment Cost Index and annual inflation rate 3.27 Worldwide upstream oil and gas capital spending 3.28 Upstream oil and gas investment and operating costs by region 3.29 How government policy action affects the oil investment cycle

Chapter 4: The outlook for unconventional oil 4.1 Canadian oil-sands production by type in the New Policies Scenario Main Canadian oil-sands districts 4.2 4.3 Well-to-wheels greenhouse-gas emissions of various oils

148 149 157

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4.4 4.5 4.6 4.7 4.8

Venezuelan oil production by type in the New Policies Scenario Continuum from conventional to unconventional oil resources Shale-oil production by country in the New Policies Scenario Coal-to-liquids production by country in the New Policies Scenario Gas-to-liquids production by source in the New Policies Scenario

Chapter 5: Natural gas market outlook 5.1 World primary natural gas demand by scenario World primary natural gas demand by sector in the New Policies Scenario 5.2 5.3 Proven reserves, recoverable resources and production of conventional natural gas by region in the New Policies Scenario 5.4 World natural gas production by type in the New Policies Scenario 5.5 Change in natural gas production by region in the New Policies Scenario 5.6 Inter-regional natural gas net trade flows between major regions in the New Policies Scenario 5.7 World inter-regional natural gas trade by type in the New Policies Scenario 5.8 Natural gas transportation capacity between major regions in the New Policies Scenario

Chapter 6: Coal market outlook 6.1 World primary coal demand by scenario Share of key regions in global primary coal demand in the New Policies 6.2 Scenario 6.3 Change in primary coal demand by sector and region in the New Policies Scenario, 2008-2035 6.4 Power generation costs by fuel and distances in China, 2009 6.5 Coal supply cash-cost curve for internationally traded steam coal for 2009 and average FOB prices for 2009 and first-half 2010 Chapter 7: Power sector outlook 7.1 World electricity generation by type in the New Policies Scenario 7.2 Coal-fired electricity generation by region in the New Policies Scenario 7.3 Coal-fired electricity generation by technology and region in the New Policies Scenario 7.4 Share of nuclear and renewable energy in total electricity generation by region in the New Policies Scenario 7.5 Nuclear capacity under construction and additions by region in the New Policies Scenario 7.6 CO2 intensity of power generation by region in the New Policies Scenario 7.7 CO2 emissions from the power sector by region in the New Policies Scenario 7.8 World power-generation capacity additions and investment by type in the New Policies Scenario 7.9 Age profile of installed thermal and nuclear capacity by region, 2008 7.10 World installed power-generation capacity by type in the New Policies Scenario 7.11 Power-generation capacity by type in the United States in the New Policies Scenario 28

Electricity generation by fuel and region in the New Policies Scenario Cumulative capacity additions in China in the New Policies Scenario from 2009 compared with the 2008 installed capacity of selected countries Change in electricity generation relative to 2008 by type for selected countries in the New Policies Scenario

Chapter 8: Energy poverty 8.1 Number of people without access to electricity in rural and urban areas in the New Policies Scenario 8.2 Residential electricity consumption in New York and sub-Saharan Africa 8.3 Household income and electricity access in developing countries 8.4 Household income and access to modern fuels in developing countries 8.5 Premature annual deaths from household air pollution and other diseases 8.6 Access to modern energy services in the New Policies Scenario and Universal Modern Energy Access Case 8.7 Implication of eradicating extreme poverty on number of people without access to electricity by 2015 8.8 Global implications for electricity generation and CO2 emissions in the Universal Modern Energy Access Case, 2030 8.9 Number and share of population relying on the traditional use of biomass as their primary cooking fuel by region, 2009 8.10 Implication of reducing poverty for number of people relying on the traditional use of biomass for cooking by 2015 8.11 Global implications for oil demand in the Universal Modern Energy Access Case 8.12 Number of people gaining access to electricity and additional cumulative investment needs in the Universal Modern Energy Access Case 8.13 Incremental electricity generation and investment in the Universal Modern Energy Access Case, 2010-2030 8.14 Number of people gaining clean cooking facilities and additional cumulative investment needs in the Universal Modern Energy Access Case 8.15 Annual average additional investment needs in the Universal Modern Energy Access Case compared with fossil-fuel subsidies in developing countries in 2009 8.16 2010 Energy Development Index 8.17 Comparison of the Human Development Index to the Energy Development Index 8.18 Evolution of household access to modern energy in selected developing countries 8.19 The relationship between per-capita final energy consumption and income in developing countries 8.20 The quality of energy services and household income

Increase in global modern renewables by type and scenario, 2008-2035 Modern renewables primary energy demand by region in the New Policies Scenario World modern biomass primary demand by sector in the New Policies Scenario Quarterly global investment in renewable energy assets Annual investment in renewable energy assets by region Finance of renewables by region and type Cumulative investment in renewables by type and selected country/region in the New Policies Scenario, 2010-2035 Annual global support for renewables in the New Policies Scenario Global spending on research and development in renewable energy by technology, 2009 Contribution of renewables to the global emission and oil-import bill savings in 2035 in the New Policies Scenario vis-à-vis the Current Policies Scenario

Chapter 10: Renewables for electricity 10.1 World incremental electricity generation by fuel, 2000-2008 10.2 Electricity generation from renewables by scenario 10.3 Incremental renewables-based electricity generation by region in the New Policies Scenario, 2008-2035 10.4 Share of renewables in total electricity generation by type and region in the New Policies Scenario 10.5 Electricity generating costs of renewable energy technologies for largescale electricity generation in the New Policies Scenario 10.6 Investment in renewables-based electricity generation by region in the New Policies Scenario, 2010-2035 10.7 Global cumulative capacity additions and investment in renewablesbased electricity generation by technology in the New Policies Scenario, 2010-2035 10.8 Global government support for renewables-based electricity generation by technology 10.9 Global government support for and generation from solar PV and onshore wind in the New Policies Scenario 10.10 Global government support for renewables-based electricity generation by region in the New Policies Scenario 10.11 Average wholesale electricity prices and impact of renewable support in selected OECD regions in the New Policies Scenario, 2010-2035 10.12 Shares of variable renewables in total electricity generation by region in the New Policies Scenario 10.13 Power generation system flexibility by region in the New Policies Scenario, 2035 10.14 Offshore wind power generation capacity by region and scenario 10.15 CSP electricity generating costs in MENA in the New Policies Scenario, 2035 30

CSP generating costs in North Africa and European wholesale electricity price in the New Policies Scenario

Chapter 11: Renewables for heat 11.1 Final energy consumption by energy service, 2008 Share of heat in total final energy consumption in selected countries, 2008 11.2 11.3 Share of renewables in total heat demand by type in selected OECD countries, 2008 11.4 Traditional biomass demand by region in the New Policies Scenario 11.5 Modern renewables for heat in the industry and buildings sectors in the New Policies Scenario 11.6 Global modern biomass for heat in selected industries in the New Policies Scenario 11.7 Solar heat consumption in the buildings sector by region in the New Policies Scenario 11.8 Total solar heat capacity by region, 2008

337 341 341 342 344 345 347 347 351

Chapter 12: Renewables for transport 12.1 Biofuels production in key regions 357 12.2 Biofuels consumption by region in the New Policies Scenario 360 12.3 Share of biofuels in total road-fuel consumption in selected regions by type in the New Policies Scenario 361 12.4 Cumulative investment in biofuel production facilities in the New Policies Scenario by technology, 2010-2035 363 12.5 Value of annual global government support to biofuels by type 367 12.6 Global average annual government support to biofuels in the New Policies Scenario 369 12.7 Ranges of well-to-wheels emission savings relative to gasoline and diesel 373 12.8 Indicative cost ranges of selected biofuels versus gasoline and diesel prices 375

Part C: ACHIEVING THE 450 SCENARIO AFTER COPENHAGEN Chapter 13: Energy and the ultimate climate change target 13.1 Energy-related CO2 emissions in Annex I and non-Annex I countries under the Copenhagen Accord in 2020 13.2 World energy-related CO2 emissions by scenario 13.3 Greenhouse-gas concentration trajectories by scenario 13.4 World anthropogenic greenhouse-gas emissions by type in the 450 Scenario 13.5 Energy-related CO2 emissions by region in the 450 Scenario 13.6 Energy-related CO2 emissions per capita by region in the 450 Scenario 13.7 Average annual change in CO2 intensity by scenario 13.8 World energy-related CO2 emission savings by region in the 450 Scenario 13.9 World energy-related CO2 emission savings by policy measure in the 450 Scenario 13.10 World primary energy demand by fuel in the 450 Scenario

Primary energy demand by fuel and region in the 450 Scenario Modern renewables primary energy demand by selected country/region in the 450 Scenario World electricity demand by sector in the 450 Scenario compared with the Current Policies Scenario Cumulative additional spending on low-carbon energy technologies in the 450 Scenario relative to the Current Policies Scenario Annual additional spending on low-carbon energy technologies in the 450 Scenario relative to the Current Policies Scenario Estimates of the percentage change in world GDP implied by the 450 Scenario in WEO-2009 and WEO-2010 Change in additional cumulative investment in WEO-2010 450 Scenario relative to WEO-2009 450 Scenario, 2010-2030 World energy-related CO2 emission savings by policy measure in the 450 Scenario compared with the New Policies Scenario Additional annual investment and abatement by scenario World energy-related CO2 emissions savings by region/country in the 450 Scenario compared with the New Policies Scenario Abatement by major region in the 450 Scenario compared with the New Policies Scenario

Chapter 14: The energy transformation by sector 14.1 Share of total energy-related CO2 emissions by sector and scenario 14.2 Energy-related CO2 emissions abatement by sector in the 450 Scenario compared with the Current Policies Scenario 14.3 World installed coal-fired generation capacity in the 450 Scenario relative to the Current Policies Scenario 14.4 Incremental world electricity generation by fuel and scenario, 2008-2035 14.5 World electricity generation by type and scenario 14.6 Change in world CO2 emissions from power generation in the 450 Scenario compared with the Current Policies Scenario 14.7 Change in world CO2 emissions from power generation in the 450 Scenario compared with 2008 14.8 Share of average annual global investment by technology type in the 450 Scenario 14.9 Additional price impact of the cost increase to the electricity producer in selected OECD+ countries resulting from the CO2 price in the 450 Scenario 14.10 Average annual global support for renewable electricity by scenario 14.11 Average wholesale electricity prices and renewable support costs by scenario and major region, 2010-2035 14.12 World fuel consumption in the transport sector in the 450 Scenario 14.13 Vehicle sales by type and scenario, 2035 14.14 World transport-related CO2 emission abatement in the 450 Scenario 14.15 Sales of electric and plug-in hybrid vehicles in the 450 Scenario and CO2 intensity in the power sector by scenario 32

Cumulative incremental investment in transport by mode in the 450 Scenario relative to the Current Policies Scenario Industrial energy demand by scenario Change in industrial energy-related CO2 emissions by scenario and region, 2008-2035 Share in additional investment, CO2 reduction and energy savings in industry by region in the 450 Scenario Change in energy-related CO2 emissions in the buildings sector by scenario and region, 2008-2035 Investment by region and fuel in the buildings sector

434 436 437 438 440 441

Chapter 15: Implications for oil markets 15.1 Change in oil demand by region in the 450 Scenario compared with 2008 446 15.2 Annual average change in world oil demand by sector in the 450 Scenario 447 15.3 Average IEA crude oil import price by scenario 448 15.4 Share of world energy-related CO2 emissions by fuel and scenario 448 15.5 World oil production by source in the 450 Scenario 449 15.6 Change in oil production by source and scenario, 2009-2035 451 15.7 World oil production by type in the 450 Scenario 451 15.8 Cumulative oil sector investment by region and activity in the 450 Scenario, 2010-2035 452 15.9 Oil-import bills in selected countries by scenario 455 15.10 Oil-import bills as a share of GDP at market exchange rates in selected countries by scenario 456 15.11 Energy intensity and per-capita consumption in the Middle East by scenario 457 15.12 Cumulative OPEC oil-export revenues by scenario 458

Part D: OUTLOOK FOR CASPIAN ENERGY Chapter 16: Caspian domestic energy prospects 16.1 Key energy features of Caspian countries 16.2 Total primary energy demand in the Caspian by country 16.3 Total energy production in the Caspian by country 16.4 Energy subsidies in selected Caspian countries, 2009 16.5 Primary energy demand in the Caspian by fuel in the New Policies Scenario 16.6 Energy savings potential in the main Caspian countries, 2008 16.7 Primary energy intensity in the Caspian and Russia in the New Policies Scenario 16.8 Comparison of per-capita primary energy demand to GDP per capita in the New Policies Scenario (1990, 2000, 2008, 2020, 2035) 16.9 Incremental energy demand in the Caspian by sector and fuel in the New Policies Scenario, 2008-2035 16.10 Road oil consumption and passenger light-duty vehicle ownership in the Caspian in the New Policies Scenario 16.11 Electricity generation in the Caspian by country and fuel, 2008 16.12 Electricity generation in the Caspian by fuel in the New Policies Scenario

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462 464 466 470 471 473 475 475 476

16.13 16.14 16.15 16.16 16.17 16.18 16.19 16.20 16.21 16.22

Age profile of installed thermal and nuclear capacity in the Caspian, 2008 Cumulative power sector investment in the Caspian by country and type in the New Policies Scenario, 2010-2035 Incremental energy demand in Azerbaijan by sector and fuel in the New Policies Scenario, 2008-2035 Electricity generation in Azerbaijan by fuel in the New Policies Scenario Incremental energy demand in Kazakhstan by sector and fuel in the New Policies Scenario, 2008-2035 Electricity generation in Kazakhstan by fuel in the New Policies Scenario Incremental energy demand in Turkmenistan by sector and fuel in the New Policies Scenario, 2008-2035 Primary natural gas demand in Uzbekistan by sector in the New Policies Scenario Electricity generation in Uzbekistan by fuel in the New Policies Scenario Incremental energy demand in Armenia, Georgia, Kyrgyz Republic and Tajikistan by sector and fuel in the New Policies Scenario, 2008-2035

Chapter 17: Hydrocarbon resources and supply potential 17.1 Caspian oil balance in the New Policies Scenario 17.2 Caspian gas balance in the New Policies Scenario 17.3 Estimated Caspian oil and gas production by type of company, 2009 17.4 Oil production in the Caspian by major field in the New Policies Scenario 17.5 Azerbaijan’s oil balance in the New Policies Scenario 17.6 Main oil deposits and export routes in the South Caucasus 17.7 Azerbaijan’s oil net exports and transit capacity by source in the South Caucasus in the New Policies Scenario 17.8 Kazakhstan’s oil balance in the New Policies Scenario 17.9 Oil fields and infrastructure in the North Caspian 17.10 Main oil deposits and export routes in Central Asia 17.11 Kazakhstan’s oil net exports and transit capacity in the New Policies Scenario 17.12 Caspian oil export flows, 2009 17.13 Estimated Caspian oil export netbacks 17.14 Natural gas production in the Caspian by major field in the New Policies Scenario 17.15 Azerbaijan’s natural gas balance in the New Policies Scenario 17.16 Natural gas export routes in the South Caucasus 17.17 Kazakhstan’s natural gas balance in the New Policies Scenario 17.18 Turkmenistan’s gas balance in the New Policies Scenario 17.19 Main natural gas deposits and pipeline routes in Central Asia 17.20 Uzbekistan’s gas balance in the New Policies Scenario Chapter 18: Regional and global implications 18.1 Oil and gas export revenues in selected Caspian countries in the New Policies Scenario 18.2 Water releases from the Toktogul reservoir by season in the Kyrgyz Republic 34

Oil and gas transit in selected Caspian countries in the New Policies Scenario 555 Share of the Caspian in world oil supply by scenario 558 Oil production in the Caspian by country in the New Policies Scenario 558 Incremental oil production by selected country in the New Policies Scenario, 2009-2035 559 Share of the Caspian in world natural gas supply by scenario 561 Natural gas production and net exports in selected Caspian countries in the New Policies Scenario 562 Caspian share of markets and imports in OECD Europe and China in the New Policies Scenario 563 Carbon intensity in Caspian countries and selected other countries in the New Policies Scenario 564 Energy-related CO2 emissions abatement in the Caspian by source in the 450 Scenario compared with the New Policies Scenario 565

Chapter 4: The outlook for unconventional oil 4.1 World unconventional oil supply by type and scenario 4.2 Natural bitumen and extra-heavy oil resources by country 4.3 Typical costs of new Canadian oil sands projects 4.4 Current and planned Canadian oil sands projects 4.5 Venezuelan Orinoco Belt extra-heavy oil projects 4.6 Oil shale resources by country 4.7 Proposed pilot shale-oil projects in the Green River area in the United States Chapter 5: Natural gas market outlook 5.1 Primary natural gas demand by region and scenario 5.2 Primary natural gas demand by region in the New Policies Scenario 5.3 Natural gas production by region and scenario 5.4 Natural gas production by region in the New Policies Scenario 5.5 Inter-regional natural gas net trade in the New Policies Scenario 5.6 Cumulative investment in gas-supply infrastructure by region and activity in the New Policies Scenario, 2010-2035 36

Chapter 6: Coal market outlook 6.1 World primary coal demand by region and scenario Primary coal demand by region in the New Policies Scenario 6.2 6.3 Coal production by region in the New Policies Scenario 6.4 Inter-regional hard coal net trade by region in the New Policies Scenario 6.5 Production, exports and investment of 25 leading coal companies Chapter 7: Power sector outlook 7.1 Final electricity consumption by region and scenario 7.2 Capacity and investment needs in power infrastructure by region in the New Policies Scenario Chapter 8: Energy poverty 8.1 Number of people without access to electricity and relying on the traditional use of biomass, 2009 8.2 Targets in the Universal Modern Energy Access Case 8.3 Number of people without access to electricity and electrification rates by region in the New Policies Scenario 8.4 Generation requirements for universal electricity access, 2030 8.5 Number of people relying on the traditional use of biomass and share by region in the New Policies Scenario 8.6 Investment requirements for electricity in the Universal Modern Energy Access Case 8.7 Investment requirements for clean cooking facilities in the Universal Modern Energy Access Case 8.8 The minimum and maximum values used in the calculation of the 2010 Energy Development Index 8.9 Indicators of the reliability of infrastructure services 8.10 Number of developing countries with energy access targets

Chapter 9: How renewable energy markets are evolving 9.1 Global modern renewable energy supply and shares in total by scenario 9.2 Shares of renewable energy by sector and region in the New Policies Scenario 9.3 Credit projections for the United States and Euro area 9.4 The world’s ten largest owners of renewables-based electricity and biofuel producing facilities, as of June 2010 9.5 Global market shares of top-ten wind turbine manufacturers 9.6 Global market shares of top-ten solar cell manufacturers 9.7 Mergers and acquisitions in renewable energy

279 281 289 290 291 292 292

Chapter 10: Renewables for electricity 10.1 Generating costs of renewables-based electricity generation by technology 310 and learning rates in the New Policies Scenario 10.2 Investment in renewables-based electricity generation by technology in the New Policies Scenario 311 10.3 Classification of support mechanisms for renewables-based electricity 313 Table of contents

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10.4 10.5 10.6 10.7 10.8 10.9

Government support schemes for renewables-based electricity generation and quantification method Integration costs of variable renewables in the European Union and the United States in the New Policies Scenario, 2035 Installed offshore wind power capacity by country Technical solar potential at different levels of insolation and total electricity generation in selected MENA countries, 2008 Renewable energy policies and targets in selected MENA countries Renewables-based electricity generation in MENA by scenario

316 326 328 331 332 334

Chapter 11: Renewables for heat 11.1 Share of modern renewables for heat in total heat demand by region in the New Policies Scenario 11.2 Cost comparison of water heaters in China 11.3 Examples of policies for renewable heat in OECD countries

345 349 352

Chapter 12: Renewables for transport 12.1 World biofuels production, 2009 12.2 World biofuels consumption by scenario 12.3 Current government support measures for biofuels in selected countries 12.4 Value of government support to biofuels in selected countries

356 358 364 368

Part C: ACHIEVING THE 450 SCENARIO AFTER COPENHAGEN Chapter 13: Energy and the ultimate climate change target 13.1 Principal policy assumptions in the 450 Scenario by region 13.2 Key abatement by policy area 13.3 Emissions of major air pollutants by region in the 450 Scenario 13.4 Estimated life-years lost due to exposure to anthropogenic emissions of PM2.5 13.5 Abatement measures in China in the 450 Scenario compared with the New Policies Scenario in 2020

Chapter 14: The energy transformation by sector 14.1 Capacity additions by fuel and region in the 450 Scenario Chapter 15: Implications for oil markets 15.1 Key oil market indicators by scenario 15.2 Primary oil demand by region in the 450 Scenario 15.3 World oil demand by sector in the 450 Scenario 15.4 Oil supply by source in the 450 Scenario 15.5 Oil net imports in key regions in the 450 Scenario 15.6 Oil intensity by region in the 450 Scenario 15.7 Emissions of energy-related CO2 and major air pollutants in the Middle East by scenario 38

387 395 407 408 413 420 444 445 447 450 454 456 458

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Part D: OUTLOOK FOR CASPIAN ENERGY Chapter 16: Caspian domestic energy prospects 16.1 Key energy indicators for the Caspian Indicators and assumptions for population and GDP in the Caspian 16.2 16.3 Primary energy demand by country in the Caspian by scenario 16.4 Primary energy demand in Azerbaijan by fuel in the New Policies Scenario 16.5 Primary energy demand in Kazakhstan by fuel in the New Policies Scenario 16.6 Primary energy demand in Turkmenistan by fuel in the New Policies Scenario 16.7 Primary energy demand in Uzbekistan by fuel in the New Policies Scenario 16.8 Primary energy demand in Armenia, Georgia, Kyrgyz Republic and Tajikistan by fuel in the New Policies Scenario Chapter 17: Hydrocarbon resources and supply potential 17.1 Conventional oil resources in the Caspian by country, end-2009 Oil production in the Caspian by country in the New Policies Scenario 17.2 17.3 Production-weighted average annual observed decline rates of oilfields by region 17.4 Oil net exports in the Caspian by country in the New Policies Scenario 17.5 Azerbaijan’s oil export routes 17.6 Ownership of the main Caspian upstream and midstream oil projects 17.7 Kazakhstan’s oil export routes 17.8 Conventional natural gas resources in the Caspian by country, end-2009 17.9 Plateau production characteristics and production-weighted average annual decline rates for gas fields 17.10 Natural gas production in the Caspian by country in the New Policies Scenario 17.11 Natural gas net exports in the Caspian by country in the New Policies Scenario 17.12 Azerbaijan’s main westward gas-export pipeline projects

Chapter 3: Oil market outlook 3.1 Defining and measuring oil and gas reserves and resources 3.2 Definitions of different types of oil in the WEO 3.3 Enhancements to the oil-supply model for WEO-2010 3.4 Impact of the Gulf of Mexico oil spill 3.5 The renaissance of Iraqi oil production

114 116 121 129 132

Chapter 4: The outlook for unconventional oil 4.1 How oil is formed 4.2 Life-cycle emissions 4.3 When oil from shales is not shale oil: the case of the Bakken 4.4 Exploiting deep shales: the case of the Bazhenov formation in Russia

Chapter 8: Energy poverty 8.1 Cooking and lighting in the poorest households 8.2 The importance of modern energy in achieving the MDGs 8.3 Renewable energy for rural applications 8.4 Measuring progress with energy poverty indicators 8.5 Going beyond household access: indicators at the village and national level 8.6 Initiatives to improve the efficiency of biomass for cooking

Chapter 11: Renewables for heat 11.1 Expanding the production of heat from biomass in the industry sector The impact of technology development on the uptake of solar for heat 11.2 11.3 Renewables for heat in the 450 Scenario 11.4 Heat pumps 11.5 Renewable heat obligations and feed-in tariffs in the European Union

Part C: ACHIEVING THE 450 SCENARIO AFTER COPENHAGEN Chapter 13: Energy and the ultimate climate change target 13.1 Uncertainties around the interpretation of Copenhagen Accord Pledges 13.2 Impact on government revenues

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Chapter 14: The energy transformation by sector 14.1 Carbon capture and storage 14.2 The policy framework for the transport sector in the 450 Scenario 14.3 The policy framework for the industry sector in the 450 Scenario 14.4 The policy framework for the buildings sector in the 450 Scenario

The energy world faces unprecedented uncertainty. The global economic crisis of 2008-2009 threw energy markets around the world into turmoil and the pace at which the global economy recovers holds the key to energy prospects for the next several years. But it will be governments, and how they respond to the twin challenges of climate change and energy security, that will shape the future of energy in the longer term. The economic situation has improved considerably over the past 12 months, more than many dared to hope for. Yet the economic outlook for the coming years remains hugely uncertain, amid fears of a double-dip recession and burgeoning government budget deficits, making the medium-term outlook for energy unusually hard to predict with confidence. The past year has also seen notable steps forward in policy making, with the negotiation of important international agreements on climate change and on the reform of inefficient fossil-fuel subsidies. And the development and deployment of low-carbon technologies received a significant boost from stepped-up funding and incentives that governments around the world introduced as part of their fiscal stimulus packages. Together, these moves promise to drive forward the urgently needed transformation of the global energy system. But doubts remain about the implementation of recent policy commitments. Even if they are acted upon, much more needs to be done to ensure that this transformation happens quickly enough.

The outcome of the landmark UN conference on climate change held in December 2009 in Copenhagen was a step forward, but still fell a very long way short of what is required to set us on the path to a sustainable energy system. The Copenhagen Accord — with which all major emitting countries and many others subsequently associated themselves — sets a non-binding objective of limiting the increase in global temperature to two degrees Celsius (2°C) above pre-industrial levels. It also establishes a goal for the industrialised countries of mobilising funding for climate mitigation and adaptation in developing countries of $100 billion per year by 2020, and requires the industrialised countries to set emissions targets for the same year. This followed a call from G8 leaders at their July 2009 summit to share with all countries the goal of cutting global emissions by at least 50% by 2050. But the commitments that were subsequently announced, even if they were to be fully implemented, would take us only part of the way towards an emissions trajectory that would allow us to achieve the 2°C goal. That does not mean that the goal is completely out of reach. But it does mean that much stronger efforts, costing considerably more, will be needed after 2020. Indeed, the speed of the energy transformation that would need to occur after 2020 is such as to raise serious misgivings about the practical achievability of cutting emissions sufficiently to meet the 2°C goal. The commitment made by G-20 leaders meeting in the US city of Pittsburgh in September 2009 to “rationalize and phase out over the medium term inefficient fossil-fuel subsidies that encourage wasteful consumption” has the potential to, at least partly, balance the disappointment at Copenhagen. This commitment was Executive summary

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made in recognition that subsidies distort markets, can impede investment in clean energy sources and can thereby undermine efforts to deal with climate change. The analysis we have carried out in collaboration with other international organisations at the request of G-20 leaders, and which is set out in this Outlook, shows that removing fossil-fuel consumption subsidies, which totalled $312 billion in 2009, could make a big contribution to meeting energy-security and environmental goals, including mitigating carbon-dioxide (CO2) and other emissions.

The world energy outlook to 2035 hinges critically on government policy action, and how that action affects technology, the price of energy services and end-user behaviour. In recognition of the important policy advances that have been made recently, the central scenario in this year’s Outlook — the New Policies Scenario — takes account of the broad policy commitments and plans that have been announced by countries around the world, including the national pledges to reduce greenhousegas emissions and plans to phase out fossil-energy subsidies even where the measures to implement these commitments have yet to be identified or announced. These commitments are assumed to be implemented in a relatively cautious manner, reflecting their non-binding character and, in many cases, the uncertainty shrouding how they are to be put into effect. This scenario allows us to quantify the potential impact on energy markets of implementation of those policy commitments, by comparing it with a Current Policies Scenario (previously called the Reference Scenario), in which no change in policies as of mid-2010 is assumed, i.e. that recent commitments are not acted upon. We also present the results of the 450 Scenario, which was first presented in detail in WEO-2008, which sets out an energy pathway consistent with the 2°C goal through limitation of the concentration of greenhouse gases in the atmosphere to around 450 parts per million of CO2 equivalent (ppm CO2-eq). The policy commitments and plans that governments have recently announced would, if implemented, have a real impact on energy demand and related CO2 emissions. In the New Policies Scenario, world primary energy demand increases by 36% between 2008 and 2035, from around 12 300 million tonnes of oil equivalent (Mtoe) to over 16 700 Mtoe, or 1.2% per year on average. This compares with 2% per year over the previous 27-year period. The projected rate of growth in demand is lower than in the Current Policies Scenario, where demand grows by 1.4% per year over 2008-2035. In the 450 Scenario, demand still increases between 2008 and 2035, but by only 0.7% per year. Energy prices ensure that projected supply and demand are in balance throughout the Outlook period in each scenario, rising fastest in the Current Policies Scenario and slowest in the 450 Scenario. Fossil fuels — oil, coal and natural gas — remain the dominant energy sources in 2035 in all three scenarios, though their share of the overall primary fuel mix varies markedly. The shares of renewables and nuclear power are correspondingly highest in the 450 Scenario and lowest in the Current Policies Scenario. The range of outcomes — and therefore the uncertainty with respect to future energy use — is largest for coal, nuclear power and non-hydro renewable energy sources. 46

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Emerging economies, led by China and India, will drive global demand higher In the New Policies Scenario, global demand for each fuel source increases, with fossil fuels accounting for over one-half of the increase in total primary energy demand. Rising fossil-fuel prices to end users, resulting from upward price pressures on international markets and increasingly onerous carbon penalties, together with policies to encourage energy savings and switching to low-carbon energy sources, help to restrain demand growth for all three fossil fuels. Oil remains the dominant fuel in the primary energy mix during the Outlook period, though its share of the primary fuel mix, which stood at 33% in 2008, drops to 28% as high prices and government measures to promote fuel efficiency lead to further switching away from oil in the industrial and power-generation sectors, and new opportunities emerge to substitute other fuels for oil products in transport. Demand for coal rises through to around 2020 and starts to decline towards the end of the Outlook period. Growth in demand for natural gas far surpasses that for the other fossil fuels due to its more favourable environmental and practical attributes, and constraints on how quickly low-carbon energy technologies can be deployed. The share of nuclear power increases from 6% in 2008 to 8% in 2035. The use of modern renewable energy — including hydro, wind, solar, geothermal, modern biomass and marine energy — triples over the course of the Outlook period, its share in total primary energy demand increasing from 7% to 14%. Consumption of traditional biomass rises slightly to 2020 and then falls back to just below current levels by 2035, with increased use of modern fuels by households in the developing world.

Non-OECD countries account for 93% of the projected increase in world primary energy demand in the New Policies Scenario, reflecting faster rates of growth of economic activity, industrial production, population and urbanisation. China, where demand has surged over the past decade, contributes 36% to the projected growth in global energy use, its demand rising by 75% between 2008 and 2035. By 2035, China accounts for 22% of world demand, up from 17% today. India is the second-largest contributor to the increase in global demand to 2035, accounting for 18% of the rise, its energy consumption more than doubling over the Outlook period. Outside Asia, the Middle East experiences the fastest rate of increase, at 2% per year. Aggregate energy demand in OECD countries rises very slowly over the projection period. Nonetheless, by 2035, the United States is still the world’s second-largest energy consumer behind China, well ahead of India (in a distant third place). It is hard to overstate the growing importance of China in global energy markets. Our preliminary data suggest that China overtook the United States in 2009 to become the world’s largest energy user. Strikingly, Chinese energy use was only half that of the United States in 2000. The increase in China’s energy consumption between 2000 and 2008 was more than four times greater than in the previous decade. Prospects for further growth remain strong, given that China’s per-capita consumption level remains low, at only one-third of the OECD average, and that it is the most populous nation on the planet, with more than 1.3 billion people. Consequently, the global energy projections in this Outlook remain highly sensitive to the underlying assumptions for the key variables that drive energy demand in China, including prospects for economic Executive summary

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growth, changes in economic structure, developments in energy and environmental policies, and the rate of urbanisation. The country’s growing need to import fossil fuels to meet its rising domestic demand will have an increasingly large impact on international markets. Given the sheer scale of China’s domestic market, its push to increase the share of new low-carbon energy technologies could play an important role in driving down their costs through faster rates of technology learning and economies of scale.

Will peak oil be a guest or the spectre at the feast? The oil price needed to balance oil markets is set to rise, reflecting the growing insensitivity of both demand and supply to price. The growing concentration of oil use in transport and a shift of demand towards subsidised markets are limiting the scope for higher prices to choke off demand through switching to alternative fuels. And constraints on investment mean that higher prices lead to only modest increases in production. In the New Policies Scenario, the average IEA crude oil price reaches $113 per barrel (in year-2009 dollars) in 2035 — up from just over $60 in 2009. In practice, short-term price volatility is likely to remain high. Oil demand (excluding biofuels) continues to grow steadily, reaching about 99 million barrels per day (mb/d) by 2035 — 15 mb/d higher than in 2009. All of the net growth comes from non-OECD countries, almost half from China alone, mainly driven by rising use of transport fuels; demand in the OECD falls by over 6 mb/d. Global oil production reaches 96 mb/d, the balance of 3 mb/d coming from processing gains. Crude oil output reaches an undulating plateau of around 68-69 mb/d by 2020, but never regains its all-time peak of 70 mb/d reached in 2006, while production of natural gas liquids (NGLs) and unconventional oil grows strongly.

Total OPEC production rises continually through to 2035 in the New Policies Scenario, boosting its share of global output to over one-half. Iraq accounts for a large share of the increase in OPEC output, commensurate with its large resource base, its crude oil output catching up with Iran’s by around 2015 and its total output reaching 7 mb/d by 2035. Saudi Arabia regains from Russia its place as the world’s biggest oil producer, its output rising from 9.6 mb/d in 2009 to 14.6 mb/d in 2035. The increasing share of OPEC contributes to the growing dominance of national oil companies: as a group, they account for all of the increase in global production between 2009 and 2035. Total non-OPEC oil production is broadly constant to around 2025, as rising production of NGLs and unconventional oil offsets a fall in that of crude oil; thereafter, total non-OPEC output starts to drop. The size of ultimately recoverable resources of both conventional and unconventional oil is a major source of uncertainty for the long-term outlook for world oil production. Clearly, global oil production will peak one day, but that peak will be determined by factors affecting both demand and supply. In the New Policies Scenario, production in total does not peak before 2035, though it comes close to doing so. By contrast, production does peak, at 86 mb/d, just before 2020 in the 450 Scenario, as a result of weaker demand, falling briskly thereafter. Oil prices are much lower as a result. The message is clear: if governments act more vigorously than currently planned to encourage 48

World Energy Outlook 2010

more efficient use of oil and the development of alternatives, then demand for oil might begin to ease soon and, as a result, we might see a fairly early peak in oil production. That peak would not be caused by resource constraints. But if governments do nothing or little more than at present, then demand will continue to increase, supply costs will rise, the economic burden of oil use will grow, vulnerability to supply disruptions will increase and the global environment will suffer serious damage.

Unconventional oil is abundant but more costly Unconventional oil is set to play an increasingly important role in world oil supply through to 2035, regardless of what governments do to curb demand. In the New Policies Scenario, output rises from 2.3 mb/d in 2009 to 9.5 mb/d in 2035. Canadian oil sands and Venezuelan extra-heavy oil dominate the mix, but coal-to-liquids, gas-to-liquids and, to a lesser extent, oil shales also make a growing contribution in the second half of the Outlook period. Unconventional oil resources are thought to be huge — several times larger than conventional oil resources. The rate at which they will be exploited will be determined by economic and environmental considerations, including the costs of mitigating their environmental impact. Unconventional sources of oil are among the more expensive available: they require large upfront capital investment, which is typically paid back over long periods. Consequently, they play a key role in setting future oil prices. The production of unconventional oil generally emits more greenhouse gases per barrel than that of most types of conventional oil, but, on a well-to-wheels basis, the difference is much less, as most emissions occur at the point of use. In the case of Canadian oil sands, well-to-wheels CO2 emissions are typically between 5% and 15% higher than for conventional crude oils. Mitigation measures will be needed to reduce emissions from unconventional oil production, including more efficient extraction technologies, carbon capture and storage and, with coal-to-liquids plants, the addition of biomass to the coal feedstock. Improved water and land management, though not unique to unconventional sources, will also be required to make the development of these resources and technologies more acceptable.

China could lead us into a golden age for gas Natural gas is certainly set to play a central role in meeting the world’s energy needs for at least the next two-and-a-half decades. Global natural gas demand, which fell in 2009 with the economic downturn, is set to resume its long-term upward trajectory from 2010. It is the only fossil fuel for which demand is higher in 2035 than in 2008 in all scenarios, though it grows at markedly different rates. In the New Policies Scenario, demand reaches 4.5 trillion cubic metres (tcm) in 2035 — an increase of 1.4 tcm, or 44%, over 2008 and an average rate of increase of 1.4% per year. China’s demand grows fastest, at an average rate of almost 6% per year, and the most in volume terms, accounting for more than one-fifth of the increase in global demand to 2035. There is potential for Chinese gas demand to grow even faster than this, especially if coal use is restrained for environmental reasons. Demand in the Executive summary

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Middle East increases almost as much as projected in China. The Middle East, which is well-endowed with relatively low-cost resources, leads the expansion of gas production over the Outlook period, its output doubling to 800 billion cubic metres (bcm) by 2035. Around 35% of the global increase in gas production in the New Policies Scenario comes from unconventional sources — shale gas, coalbed methane and tight gas — in the United States and, increasingly, from other regions, notably Asia-Pacific. The glut of global gas-supply capacity that has emerged as a result of the economic crisis (which depressed gas demand), the boom in US unconventional gas production and a surge in liquefied natural gas (LNG) capacity, could persist for longer than many expect. Based on projected demand in the New Policies Scenario, we estimate that the glut, measured by the difference between the volumes actually traded and total capacity of inter-regional pipelines and LNG export plants, amounted to about 130 bcm in 2009; it is set to reach over 200 bcm in 2011, before starting a hesitant decline. This glut will keep the pressure on gas exporters to move away from oil-price indexation, notably in Europe, which could lead to lower prices and to stronger demand for gas than projected, especially in the power sector. In the longer term, the increasing need for imports — especially in China — will most likely drive up capacity utilisation. In the New Policies Scenario, gas trade between all WEO regions expands by around 80%, from 670 bcm in 2008 to 1 190 bcm in 2035. Well over half of the growth in gas trade takes the form of LNG.

World electricity demand is expected to continue to grow more strongly than any other final form of energy. In the New Policies Scenario, it is projected to grow by 2.2% per year between 2008 and 2035, with more than 80% of the increase occurring in non-OECD countries. In China, electricity demand triples between 2008 and 2035. Over the next 15 years, China is projected to add generating capacity equivalent to the current total installed capacity of the United States. Globally, gross capacity additions, to replace obsolete capacity and to meet demand growth, amount to around 5 900 gigawatts (GW) over the period 2009-2035 — 25% more than current installed capacity; more than 40% of this incremental capacity is added by 2020. Electricity generation is entering a period of transformation as investment shifts to low-carbon technologies — the result of higher fossil-fuel prices and government policies to enhance energy security and to curb emissions of CO2. In the New Policies Scenario, fossil fuels — mainly coal and natural gas — remain dominant, but their share of total generation drops from 68% in 2008 to 55% in 2035, as nuclear and renewable sources expand. The shift to low-carbon technologies is particularly marked in the OECD. Globally, coal remains the leading source of electricity generation in 2035, although its share of electricity generation declines from 41% now to 32%. A big increase in non-OECD coal-fired generation is partially offset by a fall in OECD countries. Gas-fired generation grows in absolute terms, mainly in the non-OECD, but maintains a stable share of world electricity generation at around 21% over the Outlook period. The share of nuclear power in generation increases only marginally, with more than 360 GW of new additions over the period and extended lifetime for several plants. 50

World Energy Outlook 2010

Globally, the shift to nuclear power, renewables and other low-carbon technologies is projected to reduce the amount of CO2 emitted per unit of electricity generated by one-third between 2008 and 2035.

The future of renewables hinges critically on strong government support Renewable energy sources will have to play a central role in moving the world onto a more secure, reliable and sustainable energy path. The potential is unquestionably large, but how quickly their contribution to meeting the world’s energy needs grows hinges critically on the strength of government support to make renewables cost-competitive with other energy sources and technologies, and to stimulate technological advances. The need for government support would increase were gas prices to be lower than assumed in our analysis.

The greatest scope for increasing the use of renewables in absolute terms lies in the power sector. In the New Policies Scenario, renewables-based generation triples between 2008 and 2035 and the share of renewables in global electricity generation increases from 19% in 2008 to almost one-third (catching up with coal). The increase comes primarily from wind and hydropower, though hydropower remains dominant over the Outlook period. Electricity produced from solar photovoltaics increases very rapidly, though its share of global generation reaches only around 2% in 2035. The share of modern renewables in heat production in industry and buildings increases from 10% to 16%. The use of biofuels grows more than four-fold between 2008 and 2035, meeting 8% of road transport fuel demand by the end of the Outlook period (up from 3% now). Renewables are generally more capital-intensive than fossil fuels, so the investment needed to provide the extra renewables capacity is very large: cumulative investment in renewables to produce electricity is estimated at $5.7 trillion (in year-2009 dollars) over the period 2010-2035. Investment needs are greatest in China, which has now emerged as a leader in wind power and photovoltaic production, as well as a major supplier of the equipment. The Middle East and North Africa region holds enormous potential for large-scale development of solar power, but there are many market, technical and political challenges that need to be overcome. Although renewables are expected to become increasingly competitive as fossil-fuel prices rise and renewable technologies mature, the scale of government support is set to expand as their contribution to the global energy mix increases. We estimate that government support worldwide for both electricity from renewables and for biofuels totalled $57 billion in 2009, of which $37 billion was for the former. In the New Policies Scenario, total support grows to $205 billion (in year-2009 dollars), or 0.17% of global GDP, by 2035. Between 2010 and 2035, 63% of the support goes to renewables-based electricity. Support per unit of generation on average worldwide drops over time, from $55 per megawatt-hour (MWh) in 2009 to $23/MWh by 2035, as wholesale electricity prices increase and their production costs fall due to technological learning. This does not take account of the additional costs of integrating them into the network, which can be significant because the variability of some types of renewables, such as wind and solar energy. Government support for renewables can, in principle, Executive summary

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be justified by the long-term economic, energy-security and environmental benefits they can bring, though attention needs to be given to the cost-effectiveness of support mechanisms. The use of biofuels — transport fuels derived from biomass feedstock — is expected to continue to increase rapidly over the projection period, thanks to rising oil prices and government support. In the New Policies Scenario, global biofuels use increases from about 1 mb/d today to 4.4 mb/d in 2035. The United States, Brazil and the European Union are expected to remain the world’s largest producers and consumers of biofuels. Advanced biofuels, including those from ligno-cellulosic feedstocks, are assumed to enter the market by around 2020, mostly in OECD countries. The cost of producing biofuels today is often higher than the current cost of imported oil, so strong government incentives are usually needed to make them competitive with oil-based fuels. Global government support in 2009 was $20 billion, the bulk of it in the United States and the European Union. Support is projected to rise to about $45 billion per year between 2010 and 2020, and about $65 billion per year between 2021 and 2035. Government support typically raises costs to the economy as a whole. But the benefits can be significant too, including reduced imports of oil and reduced CO2 emissions — if sustainable biomass is used and the fossil energy used in processing the biomass is not excessive.

Unlocking the Caspian’s energy riches would enhance the world’s energy security The Caspian region has the potential to make a significant contribution to ensuring energy security in the rest of the world, by increasing the diversity of oil and gas supplies. The Caspian region contains substantial resources of both oil and natural gas, which could underpin a sizeable increase in production and exports over the next two decades. But potential barriers to the development of these resources, notably the complexities of financing and constructing transportation infrastructure passing through several countries, the investment climate and uncertainty over export demand, are expected to constrain this expansion to some degree. In the New Policies Scenario, Caspian oil production grows strongly — especially over the first 15 years of the projection period; it jumps from 2.9 mb/d in 2009 to a peak of around 5.4 mb/d between 2025 and 2030, before falling back to 5.2 mb/d by 2035. Kazakhstan contributes all of this increase, ranking fourth in the world for output growth in volume terms to 2035 after Saudi Arabia, Iraq and Brazil. Most of the incremental oil output goes to exports, which double to a peak of 4.6 mb/d soon after 2025. Caspian gas production is also projected to expand substantially, from an estimated 159 bcm in 2009 to nearly 260 bcm by 2020 and over 310 bcm in 2035. Turkmenistan and, to a lesser extent, Azerbaijan and Kazakhstan drive this expansion. As with oil, gas exports are projected to grow rapidly, reaching nearly 100 bcm in 2020 and 130 bcm in 2035, up from less than 30 bcm in 2009. The Caspian has the potential to supply a significant part of the gas needs of Europe and China, which emerges as a major new customer, enhancing their energy diversity and security. 52

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Domestic energy policies and market trends, beyond being critical to the Caspian’s social and economic development, have an influence on world prospects by determining the volumes available for export. Despite some improvement in recent years, the region remains highly energy-intensive, reflecting continuing gross inefficiencies in the way energy is used (a legacy of the Soviet era), as well as climatic and structural economic factors. If the region were to use energy as efficiently as OECD countries, consumption of primary energy in the Caspian as a whole would be cut by one-half. How quickly this energy-efficiency potential might be exploited hinges largely on government policies, especially on energy pricing (all the main Caspian countries subsidise at least one form of fossil energy), market reform and financing. In the New Policies Scenario, total Caspian primary energy demand expands progressively through the Outlook period, at an average rate of 1.4% per year, with gas remaining the predominant fuel. Kazakhstan and Turkmenistan see the fastest rates of growth in energy use, mainly reflecting more rapid economic growth.

Copenhagen pledges are collectively far less ambitious than the overall goal

The commitments that countries have announced under the Copenhagen Accord to reduce their greenhouse-gas emissions collectively fall short of what would be required to put the world onto a path to achieving the Accord’s goal of limiting the global temperature increase to 2°C. If countries act upon these commitments in a cautious manner, as we assume in the New Policies Scenario, rising demand for fossil fuels would continue to drive up energy-related CO2 emissions through the projection period. Such a trend would make it all but impossible to achieve the 2°C goal, as the required reductions in emissions after 2020 would be too steep. In that scenario, global emissions continue to rise through the projection period, though the rate of growth falls progressively. Emissions jump to just under 34 gigatonnes (Gt) in 2020 and over 35 Gt in 2035 — a 21% increase over the 2008 level of 29 Gt. Non-OECD countries account for all of the projected growth in world emissions; OECD emissions peak before 2015 and then begin to fall. These trends are in line with stabilising the concentration of greenhouse gases at over 650 ppm CO2-eq, resulting in a likely temperature rise of more than 3.5°C in the long term. The 2°C goal can only be achieved with vigorous implementation of commitments in the period to 2020 and much stronger action thereafter. According to climate experts, in order to have a reasonable chance of achieving the goal, the concentration of greenhouse gases would need to be stabilised at a level no higher than 450 ppm CO2-eq. The 450 Scenario describes how the energy sector could evolve were this objective to be achieved. It assumes implementation of measures to realise the more ambitious end of target ranges announced under the Copenhagen Accord and more rapid implementation of the removal of fossil-fuel subsidies agreed by the G-20 than assumed in the New Policies Scenario. This action results in a significantly faster slowdown in global energy-related CO2 emissions. In the 450 Scenario, emissions reach a peak of 32 Gt just before 2020 and then slide to 22 Gt by 2035. Just ten emissions-abatement measures in five regions — the United States, the European Union, Japan, China and India — account Executive summary

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for around half of the emission reductions throughout the Outlook period needed in this scenario compared with the Current Policies Scenario. While pricing carbon in the power and industry sectors is at the heart of emissions reductions in OECD countries and, in the longer term, other major economies (CO2 prices reach $90-120 per tonne in 2035), fossil-fuel subsidies phase-out is a crucial pillar of mitigation in the Middle East, Russia and parts of Asia. The power-generation sector’s share of global emissions drops from 41% today to 24% by 2035, spearheading the decarbonisation of the global economy. By contrast, the transport sector’s share jumps from 23% to 32%, as it is more costly to cut emissions rapidly than in most other sectors. Cutting emissions sufficiently to meet the 2°C goal would require a far-reaching transformation of the global energy system. In the 450 Scenario, oil demand peaks just before 2020 at 88 mb/d, only 4 mb/d above current levels, and declines to 81 mb/d in 2035. There is still a need to build almost 50 mb/d of new capacity to compensate for falling production from existing fields, but the volume of oil which has to be found and developed from new sources by 2035 is only two-thirds that in the New Policies Scenario, allowing the oil industry to shelve some of the more costly and more environmentally sensitive prospective projects. Coal demand peaks before 2020, returning to 2003 levels by 2035. Among the fossil fuels, demand for natural gas is least affected, though it too reaches a peak before the end of the 2020s. Renewables and nuclear make significant inroads in the energy mix, doubling their current share to 38% in 2035. The share of nuclear power in total generation increases by about 50% over current levels. Renewable-based generation increases the most, reaching more than 45% of global generation — two-and-a-half times higher than today. Wind power jumps to almost 13%, while the combined share of solar PV and CSP reaches more than 6%. Carbon capture and storage plays an important role in reducing power-sector emissions: by 2035, generation from coal plants fitted with CCS exceeds that from coal plants not equipped with this technology, accounting for about three-quarters of the total generation from all CCS fitted plants. Biofuels and advanced vehicles also play a much bigger role than in the New Policies Scenario. By 2035, about 70% of global passenger-car sales are advanced vehicles (hybrids, plug-in hybrids and electric cars). Global energy security is enhanced by the greater diversity of the energy mix.

Failure at Copenhagen has cost us at least $1 trillion… Even if the commitments under the Copenhagen Accord were fully implemented, the emissions reductions that would be needed after 2020 would cost more than if more ambitious earlier targets had been pledged. The emissions reductions that those commitments would yield by 2020 are such that much bigger reductions would be needed thereafter to get on track to meet the 2°C goal. In the 450 Scenario in this year’s Outlook, the additional spending on low-carbon energy technologies (business investment and consumer spending) amounts to $18 trillion (in year-2009 dollars) more than in the Current Policies Scenario in the period 2010-2035, and around $13.5 trillion more than in the New Policies Scenario. The additional spending compared with the Current Policies Scenario to 2030 is $11.6 trillion — about $1 trillion more than we estimated last year. In addition, global GDP would be reduced in 2030 by 1.9%, 54

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compared with last year’s estimate of 0.9%. These differences are explained by the deeper, faster cuts in emissions needed after 2020, caused by the slower pace of change in energy supply and use in the earlier period.

…though reaching the Copenhagen goal is still (just about) achievable The modest nature of the pledges to cut greenhouse-gas emissions under the Copenhagen Accord has undoubtedly made it less likely that the 2°C goal will actually be achieved. Reaching that goal would require a phenomenal policy push by governments around the world. An indicator of just how big an effort is needed is the rate of decline in carbon intensity — the amount of CO2 emitted per dollar of GDP — required in the 450 Scenario. Intensity would have to fall in 2008-2020 at twice the rate of 1990-2008; between 2020 and 2035, the rate would have to be almost four times faster. The technology that exists today could enable such a change, but such a rate of technological transformation would be unprecedented. And there are major doubts about the implementation of the commitments for 2020, as many of them are ambiguous and may well be interpreted in a far less ambitious manner than assumed in the 450 Scenario. A number of countries, for instance, have proposed ranges for emissions reductions, or have set targets based on carbon or energy intensity and/or a baseline of GDP that differs from that assumed in our projections. Overall, we estimate that the uncertainty related to these factors equates to 3.9 Gt of energy-related CO2 emissions in 2020, or about 12% of projected emissions in the 450 Scenario. It is vitally important that these commitments are interpreted in the strongest way possible and that much stronger commitments are adopted and acted upon after 2020, if not before. Otherwise, the 2°C goal would probably be out of reach for good.

Getting rid of fossil-fuel subsidies is a triple-win solution Eradicating subsidies to fossil fuels would enhance energy security, reduce emissions of greenhouse gases and air pollution, and bring economic benefits. Fossil-fuel subsidies remain commonplace in many countries. They result in an economically inefficient allocation of resources and market distortions, while often failing to meet their intended objectives. Subsidies that artificially lower energy prices encourage wasteful consumption, exacerbate energy-price volatility by blurring market signals, incentivise fuel adulteration and smuggling, and undermine the competitiveness of renewables and more efficient energy technologies. For importing countries, subsidies often impose a significant fiscal burden on state budgets, while for producers they quicken the depletion of resources and can thereby reduce export earnings over the long term. Fossil-fuel consumption subsidies worldwide amounted to $312 billion in 2009, the vast majority of them in non-OECD countries. The annual level fluctuates widely with changes in international energy prices, domestic pricing policy and demand: subsidies were $558 billion in 2008. Only a small proportion of these subsidies go to the poor. Considerable momentum is now building globally to cut fossil-fuel subsidies. In September 2009, G-20 leaders committed to phase out and rationalise Executive summary

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inefficient fossil-fuel subsidies, a move that was closely mirrored in November 2009 by APEC leaders. Many countries are now pursuing reforms, but steep economic, political and social hurdles will need to be overcome to realise lasting gains. Reforming inefficient energy subsidies would have a dramatic effect on supply and demand in global energy markets. We estimate that a universal phase-out of all fossil-fuel consumption subsidies by 2020 — ambitious though it may be as an objective — would cut global primary energy demand by 5%, compared with a baseline in which subsidies remain unchanged. This amounts to the current consumption of Japan, Korea and New Zealand combined. Oil demand alone would be cut by 4.7 mb/d by 2020, equal to around one-quarter of current US demand. Phasing out fossil-fuel consumption subsidies could represent an integral building block for tackling climate change: their complete removal would reduce CO2 emissions by 5.8%, or 2 Gt, in 2020.

Despite rising energy use across the world, many poor households in developing countries still have no access to modern energy services. The numbers are striking: we estimate that 1.4 billion people — over 20% of the global population — lack access to electricity and that 2.7 billion people — some 40% of the global population — rely on the traditional use of biomass for cooking. Worse, our projections suggest that the problem will persist in the longer term: in the New Policies Scenario, 1.2 billion people still lack access to electricity in 2030 (the date of the proposed goal of universal access to modern energy services), 87% of them living in rural areas. Most of these people will be living in sub-Saharan Africa, India and other developing Asian countries (excluding China). In the same scenario, the number of people relying on the traditional use of biomass for cooking rises to 2.8 billion in 2030, 82% of them in rural areas. Prioritising access to modern energy services can help accelerate social and economic development. The UN Millennium Development Goal of eradicating extreme poverty and hunger by 2015 will not be achieved unless substantial progress is made on improving energy access. To meet the goal, an additional 395 million people need to be provided with electricity and an additional one billion provided with access to clean cooking facilities. To meet the much more ambitious goal of achieving universal access to modern energy services by 2030, additional spending of $36 billion per year would be required. This is equal to less than 3% of the global investment in energy-supply infrastructure projected in the New Policies Scenario to 2030. The resulting increase in energy demand and CO2 emissions would be modest: in 2030, global oil demand would be less than 1% higher and CO2 emissions a mere 0.8% higher compared with the New Policies Scenario. To get close to meeting either of these goals, the international community needs to recognise that the projected situation is intolerable, commit itself to effect the necessary change and set targets and indicators to monitor progress. The Energy Development Index, presented in this Outlook, could provide a basis for target-setting and monitoring. A new financial, institutional and technological framework is required, as is capacity building at the local and regional levels. Words are not enough — real action is needed now. We can and must get there in the end.

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World Energy Outlook 2010

PART A GLOBAL ENERGY TRENDS

PREFACE

Part A of this WEO presents a comprehensive summary of our energy projections for three scenarios to 2035. Our central scenario this year is called the New Policies Scenario. It takes account of the broad policy commitments and plans that have been announced by countries around the world, to tackle either environmental or energysecurity concerns, even where the measures to implement these commitments have yet to be identified or announced. This scenario allows us to quantify the potential impact on energy markets of implementation of those policy commitments, by comparing it with a Current Policies Scenario (previously called the Reference Scenario), in which no change in policies as of mid-2010 is assumed. We also present the results of the 450 Scenario, (first presented in detail in WEO-2008), which sets out an energy pathway consistent with the goal agreed at the UN climate meeting in Copenhagen in December 2009 to limit the increase in global temperature to 2°C. Chapter 1 describes the methodological framework and the assumptions that underpin the projections in each of the scenarios. Chapter 2 summarises the global trends in energy demand and supply, as well as the implications for investment and emissions of carbon dioxide. It also puts the spotlight on the increasing importance of China. The detailed projections for oil, gas, coal and electricity are then set out in Chapters 3-7, with a special focus on unconventional oil in Chapter 4.

Chapter 8 investigates the key strategic challenge of energy poverty. It quantifies the number of people without access to modern energy services in developing countries and the scale of the investments required in order to achieve the proposed goal of universal access. It also presents an Energy Development Index and a discussion of the path to improving access to modern energy services, as well as financing mechanisms and the implications for government policy.

the underlying assumptions about government policies. The New Policies Scenario, presented here for the first time, takes account of the broad policy commitments that have already been announced and assumes cautious implementation of national pledges to reduce greenhouse-gas emissions by 2020 and to reform fossil-fuel subsidies. The Current Policies Scenario (equivalent to the Reference Scenario of past Outlooks) takes into consideration only those policies that had been formally adopted by mid-2010. The third scenario, the 450 Scenario, assumes implementation of the high-end of national pledges and stronger policies after 2020, including the near-universal removal of fossil-fuel consumption subsidies, to achieve the objective of limiting the concentration of greenhouse gases in the atmosphere to 450 parts per million of CO2-equivalent and global temperature increase to 2° Celsius. Assumptions about population and economic growth are the same in each scenario. World population is assumed to expand from an estimated 6.7 billion in 2008 to 8.5 billion in 2035, an annual average rate of increase of about 1%. Population growth slows progressively, in line with past trends. The population of non-OECD countries continues to grow most rapidly. Most of the growth occurs in cities. GDP — a key driver of energy demand in all regions — is assumed to grow worldwide by 3.2% per year on average over the period 2008-2035. In general, the non-OECD countries continue to grow fastest. The world economy contracted by 0.6% in 2009, but is expected to rebound by 4.6% in 2010. India, China and the Middle East remain the fastest growing economies. In the New Policies Scenario, the IEA crude oil import price, a proxy for international prices, is assumed to rise steadily to $99/barrel (in year-2009 dollars) in 2020 and $113 in 2035, reflecting rising production costs. The price rises more rapidly in the Current Policies Scenario, as demand grows more quickly, and more slowly in the 450 Scenario, on lower demand. Natural gas prices are assumed to remain low relative to oil prices in all scenarios, notably in North America, under pressure from abundant supplies of unconventional gas. North American prices nonetheless converge to some degree with prices in Europe and Asia-Pacific over the projection period, as the cost of production climbs. Coal prices rise much less than oil and gas prices, and fall in the 450 Scenario. CO2 trading becomes more widespread and CO2 prices rise progressively in the New Policies and 450 Scenarios.

Scope and methodology This year’s edition of the World Energy Outlook (WEO) sets out long-term projections of energy demand and supply, related carbon-dioxide (CO2) emissions and investment requirements. The IEA’s World Energy Model (WEM) — a large-scale mathematical construct designed to replicate how energy markets function — is the principal tool used to generate the projections, sector-by-sector and region-by-region.1 The model has been updated, drawing on the most recent data, and parts of it enhanced, notably the transport and power-generation modules, including more detailed coverage of renewables. New models for selected countries and regions have also been developed, including separate models for the main Caspian countries. The projections have been extended from 2030 to 2035. The last year for which comprehensive historical data is available is 2008; however, preliminary data are available in some cases for 2009 and have been incorporated into the projections.

Future energy trends will be the interplay of a number of different factors, most of which are hard to predict accurately. For this reason, this World Energy Outlook adopts its customary scenario approach to analysing the long-term evolution of energy markets. In the near to medium term, economic factors are the main source of uncertainty surrounding energy prospects. There is also enormous uncertainty about the outlook for energy prices, the size of energy resources and their cost, and the prospects for new energy-related technology, especially in the longer term. But government policies are arguably the biggest source of uncertainty to 2035. Governments around the world have expressed a will to take decisive action to steer energy use onto a more environmentally and economically sustainable course, although the measures needed to bring this about, the way in which they are to be implemented and their timing are often unclear. We know that most governments will act, but how, when and how vigorously are far from clear. For these reasons, the scenarios set out in this year’s Outlook, as in past editions, derive from different underlying assumptions about policy. In this way, the Outlook provides insights into what policy can achieve and what the absence of policy action or delay in implementing policies would mean for energy markets, energy security and the environment. The past twelve months have seen some important developments in international climate policy, preparing the ground for the adoption of new measures in the coming years. The UN negotiations on climate change held in December 2009 in Copenhagen did not result in a legally-binding agreement on limiting emissions of greenhouse gases. However, the Copenhagen Accord — the agreement that was reached at the meeting and with which all major emitting countries and many others subsequently associated themselves — does set a non-binding objective of limiting the increase in global temperature to two degrees Celsius (2°C) above pre-industrial levels. It also establishes a goal for the industrialised countries to mobilise funding for climate mitigation and adaptation in developing countries of $100 billion per year by 2020, and requires the industrialised countries (Annex I countries) to set emissions targets for 2020. 1. A detailed description of the WEM can be found at www.worldenergyoutlook.org/model.asp.

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By the middle of 2010, nearly 140 countries, including many non-Annex I countries, had associated themselves with the Accord, either setting caps on their emissions for 2020 or announcing actions to mitigate emissions. However, the actual measures that would need to be taken to achieve these pledges had, in many cases, not yet been decided. Some targets are conditional on funding by Annex I countries or comparable emissions reductions across a set of countries, while other commitments involve a range. In addition, how much of the financing set out in the Accord is to be used for emissions mitigation is not specified. Some pledges relate to energy or carbon intensity, rather than emissions. As a result, it is far from certain what these commitments would mean for emissions, even if they were met fully. Since the Accord is not legally binding, the extent to which those commitments will be fulfilled remains highly uncertain. Similarly, it is uncertain what new action governments may decide to take in the coming years to deal with other concerns, such as threats to energy security, and what implications these might have for greenhouse-gas emissions.

Another important development has been the commitment made by G-20 leaders meeting in the US city of Pittsburgh in September 2009 to “rationalize and phase out over the medium term inefficient fossil fuel subsidies that encourage wasteful consumption”. This commitment was made in recognition that subsidies distort markets, can impede investment in clean energy sources and can thereby undermine efforts to deal with climate change. G-20 leaders called upon the International Energy Agency, together with the Organisation for Economic Co-operation and Development (OECD), the Organization of Petroleum Exporting Countries (OPEC) and the World Bank to provide an analysis of the extent of energy subsidies and suggestions for the action necessary to implement this commitment. The results were presented in a joint report to the subsequent G-20 summit in June 2010.2 At that summit, the leaders encouraged continued and full implementation of country-specific strategies. In this year’s Outlook, our central scenario, taking account of these political developments, takes a new form. It is called the New Policies Scenario. This scenario takes account of the broad policy commitments and plans that have been announced by countries around the world, to tackle either environmental or energy-security concerns, even where the measures to implement these commitments have yet to be identified or announced. These policies and plans include the national pledges to reduce greenhouse-gas emissions (communicated formally under the Copenhagen Accord) as well as plans to phase out fossil-energy subsidies. This scenario allows us to quantify the potential impact on energy markets of implementation of those policy commitments. But this scenario does not assume that they are all fully implemented. How governments strive to meet their policy commitments and the strength of their policy action to achieve them remains uncertain, for the reasons described above. For the purposes of this scenario, therefore, whereas we take into account action extending beyond existing policies alone (the basis of our former Reference Scenario) where there is a high degree of uncertainty, we have adopted a relatively narrow set 2. The report is available at www.worldenergyoutlook.org/subsidies.asp.

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of policy assumptions corresponding to a cautious interpretation and implementation of the climate pledges and planned subsidy reforms. Countries that have set a range for a particular target are assumed to adopt policies consistent with reaching the less ambitious end of the range. In countries where uncertainty over climate policy is very high, it is assumed that the policies adopted are insufficient to reach their target. Financing for mitigation actions is also assumed to be limited and carbon markets are assumed to grow only moderately. These assumptions may be regarded as contentious. Their adoption is not a judgment on the countries concerned, but rather a means of illustrating the implications for world energy and emissions should these assumptions prove accurate. Most of the formal national climate commitments that have been made relate to the period to 2020. For the period 2020-2035, we have assumed that additional measures are introduced that maintain the pace of the global decline in carbon intensity — measured as emissions per dollar of gross domestic product, in purchasing power parity terms — established in the period 2008-2020. The assumption of additional, but not necessarily ambitious further measures, reflects the absence of a binding international agreement to reduce global emissions. It is nonetheless assumed that each OECD country introduces an emission-reduction target across all sectors of the economy and establishes a harmonised emissions cap-and-trade scheme covering the power and industry sectors, which results in an acceleration of the decline in carbon intensity. Non-OECD countries are assumed to continue to implement national policies and measures, maintaining the pace of decline in domestic carbon intensity of 2008-2020. International sectoral agreements are assumed to be implemented across several industries, including cement and light-duty vehicles. In addition, we assume that fossil-fuel consumption subsidies are fully removed in all importing regions and are removed in exporting regions where specific policies have already been announced (Box 1.1).

We continue to present, as in previous WEOs, projections for a scenario, which we now call the Current Policies Scenario, in which no change in policies is assumed. This scenario, previously called the Reference Scenario, is intended to serve as a baseline against which the impact of new policies can be assessed. It takes into account those measures that governments had formally adopted by the middle of 2010 in response to and in pursuit of energy and environmental policies, but takes no account of any future changes in government policies and does not include measures to meet any energy or climate policy targets or commitments that have not yet been adopted or fully implemented. The Current Policies Scenario should in no sense be considered a forecast: it is certain that energy and climate policies in many — if not most — countries will change, possibly in the way we assume in the New Policies Scenario. We also present updated projections for the 450 Scenario, which was first presented in detail in WEO-2008. According to climate experts, there is a reasonable chance of limiting the global temperature increase to 2°C if the concentration of greenhouse gases in the atmosphere is limited to around 450 parts per million of carbon-dioxide equivalent (ppm CO2-eq). The 450 Scenario sets out an energy pathway consistent with that objective, albeit involving initial overshooting of the target (see Chapter 13). 62

World Energy Outlook 2010 - GLOBAL ENERGY TRENDS

For the period to 2020, the emissions path reflects an assumption of vigorous policy action to implement fully the Copenhagen Accord, including achieving the maximum emissions reductions pledged, relatively limited use of emissions-reduction credits and no use of banked allowances from earlier periods. Thus, the policies assumed are collectively consistent with the high-end of the range of commitments, resulting in a lower emissions path than in the New Policies Scenario. A summary of the policy targets and measures for 2020 taken into account in the 450 and New Policies Scenarios is set out in Table 1.1; more detailed assumptions can be found in Annex B. Box 1.1 z Summary of fossil-fuel consumption subsidy assumptions by scenario z In the New Policies Scenario, we assume that fossil-fuel subsidies are completely

phased out in all net-importing regions by 2020 (at the latest) and in netexporting regions where specific policies have already been announced. z In the Current Policies Scenario, we assume that fossil-fuel subsidies are

completely phased out in countries that already have policies in place to do so. z In the 450 Scenario, we assume fossil-fuel subsidies are completely phased out in

all net-importing regions by 2020 (at the latest) and in all net-exporting regions by 2035 (at the latest), except the Middle East where it is assumed that the average subsidisation rate declines to 20% by 2035.

After 2020, OECD countries and Other Major Economies (defined here as Brazil, China, Russia, South Africa and the countries of the Middle East) are assumed to set economywide emissions targets for 2035 and beyond that collectively ensure an emissions trajectory consistent with stabilisation of the greenhouse-gas concentration at 450 ppm. OECD countries and Other Major Economies are assumed to establish separate carbon markets, and buy offsets in other countries. Fossil-fuel consumption subsidies are assumed to be completely phased out in all regions, except the Middle East, by 2035. The emissions and energy trajectories in the period to 2020 are higher than those shown in WEO-2009 (IEA, 2009), which assumed stronger policy action in the near term, but the decline in emissions after 2020 is correspondingly faster.3 In this Outlook, we deliberately focus more attention on the results of the New Policies Scenario to provide a clear picture of where currently planned policies, if implemented in a relatively cautious way, would take us. Yet this scenario should not be interpreted as a forecast: even though it is likely that many governments around the world will take firm policy action to tackle climate and other energyrelated problems, the policies that are actually put in place in the coming years may deviate markedly from those assumed in this scenario. On the one hand, governments may decide to take stronger action to implement their current commitments than assumed in this scenario and/or may adopt more stringent targets, possibly as a result of negotiations in the coming months and years on a more robust global 3. Details of the projections for the 450 Scenario are set out in Chapter 13.

Chapter 1 - Context and analytical framework

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climate agreement. In particular, a firmer deal may emerge on financing of emissions reductions in developing countries by the industrialised countries. On the other hand, it is possible that governments will fail to implement the policies required to meet even their current pledges, especially as the Copenhagen Accord is not legally binding and contains no provision for penalising countries that fail to meet their commitments. Policy action after 2020 may also falter, putting the world on a course that takes us closer to the Current Policies Scenario. Table 1.1 z Principal policy assumptions by scenario and major region, 2020 New Policies Scenario

450 Scenario

United States

15% share of renewables in electricity generation; push for domestic supplies, including gas and biofuels.

Population Population growth is an important driver of the amount and type of energy use. The rates of population growth assumed in this Outlook for each region and in all three scenarios are based on the most recent projections by the United Nations (UNPD, 2009). World population is projected to grow by 0.9% per year on average, from an estimated 6.7 billion in 2008 to 8.5 billion in 2035. Population growth slows progressively over the projection period, in line with the long-term historical trend, from 1.1% per year in 2008-2020 to 0.7% in 2020-2035 (Table 1.2). Population expanded by 1.5% per year from 1980 to 2008 and 1.3% per year from 1990. 64

Note: The assumed rates of population growth are the same for all three scenarios presented in this Outlook. Sources: UNPD and World Bank databases; IEA analysis.

The increase in global population is expected to occur overwhelmingly in non-OECD countries, mainly in Asia and Africa (Figure 1.1). Non-OECD population expands from 5.5 billion in 2008 to 7.2 billion in 2035, an average rate of increase of 1% per year, their share of the world’s population rising from 82% to 85%. The only major non-OECD country that experiences a decline in its population is Russia, where the population falls from 142 million in 2008 to 126 million in 2035. Africa sees the fastest rate of growth, averaging 1.9% per year between 2008 and 2035. The population of non-OECD Asia rises from 3.5 billion to 4.3 billion. India overtakes China towards the end of the projection period to become the world’s most heavily populated country, with 1.47 billion people in 2035. The population of the OECD increases by only 0.4% per year on average over 2008-2035. Most of the increase in the OECD occurs in North America; Europe’s population increases slightly, while the population in the OECD Pacific region falls marginally. All of the overall increase in world population will occur in urban areas; the rural population will decline in most regions, with the notable exception of Africa (UNPD, Chapter 1 - Context and analytical framework

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2010). In 2009, for the first time in history, the world’s urban population was larger than the rural population. The population living in urban areas is projected to grow by 1.9 billion, passing from 3.3 billion in 2008 to 5.2 billion 2035, with most of this increase occurring in non-OECD countries. Continuing rapid urbanisation will push up demand for modern energy services, as they are more readily available in towns and cities. Providing access to modern energy for poor urban and rural households will remain an increasingly pressing challenge (see Chapter 8).

Economic activity is the principal driver of demand for each type of energy service. Thus, the projections in all three scenarios described in this Outlook are highly sensitive to the underlying assumptions about the rate of growth of gross domestic product (GDP). Energy demand tends to grow in line with GDP, though typically at a lower rate. For example, between 1980 and 2008, world primary energy demand increased by 0.59% each year on average for every percentage point of GDP growth (expressed in real purchasing power parity, or PPP, terms4). This (gross) income elasticity of demand, as it is known, has fluctuated over time, falling from 0.64 in the 1980s to 0.46 in the 1990s and then rebounding to 0.67 in 2000-2008, mainly because of a rapid expansion of energy-intensive manufacturing in China. In general, 4. Purchasing power parities (PPPs) measure the amount of a given currency needed to buy the same basket of goods and services, traded and non-traded, as one unit of the reference currency — in this report, the US dollar. By adjusting for differences in price levels, PPPs, in principle, can provide a more reliable indicator than market exchange rates of the true level of economic activity globally or regionally and, thus, help in analysing the main drivers of energy demand and comparing energy intensities across countries and regions. However, GDP and GDP-related indicators based on market exchange rates are used to compare trends over time, as no projections of PPPs are available.

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the income elasticity of demand tends to be higher for countries at an early stage of economic development than for the more mature economies, where saturation effects curb income-driven increases in demand. The global economy is now thought to be on the road to recovery, having endured the worst recession since the Second World War, though the threat of a double-dip recession persists. The International Monetary Fund (IMF) estimates that world GDP in PPP terms contracted by 0.6% in 2009, having expanded by 3.0% in 2008. But these figures disguise some very big differences in economic performance across the world. The recession was generally worse among the OECD economies, with most non-OECD economies experiencing a slowdown in growth rather than an outright contraction. Overall, the recession turned out to be less severe than originally expected, in part because of the strength of the policy response. Most of the world’s largest economies introduced fiscal stimulus packages between late 2008 and mid-2009, in many cases involving tax reductions or spending increases worth several percentage points of GDP. While these packages helped to counter the effects of the global financial and economic crisis, they led to a ballooning of budget deficits and a sharp rise in national debt in many countries, especially in the OECD. Many countries are now faced with a need to tackle these problems, but most want to ensure that the recovery is well-established before undertaking fiscal tightening: over-zealous action to cut deficits could, it is feared, stall the recovery and tip the economy into a downward recessionary and debt spiral.

In many parts of the developing world, economies are growing rapidly once again, allowing the countries concerned to begin to rein in their expansionary macroeconomic policies as they experience growing capital inflows and a rebound in asset prices, notably property. With growth prospects in the OECD countries likely to remain relatively weak for several years as they grapple with rising national debt, the emerging economies will remain the main drivers of the global economic recovery. However, sustained rapid growth in the non-OECD countries will hinge on their ability to absorb rising inflows of capital and to nurture domestic demand without triggering a new boom-bust cycle (IMF, 2010a). The IMF now projects global GDP growth to reach 4.6% in 2010 and 4.3% in 2011 (IMF, 2010a). The advanced economies (essentially the OECD) are projected to expand by 2.6% in 2010 and by 2.4% in 2011, following a decline in output of more than 3% in 2009. Growth in the rest of the world is projected to top 6% during 2010–11, following a modest expansion of 2.5% in 2009. Nonetheless, the IMF acknowledges that the outlook for economic activity remains unusually uncertain, and risks are generally to the downside. The risks to growth associated with the surge in public debt in the advanced economies are the most obvious, especially with respect to market concerns about sovereign liquidity and solvency in, for example, Greece and other European countries, and the danger that these concerns could evolve into a full-blown and contagious sovereign debt crisis (IMF, 2010b). Bank exposure to toxic assets, including mortgages and household debt, also threatens further turmoil in financial markets, particularly in the United States and Europe. There could be knock-on effects for growth prospects for the non-OECD countries. Chapter 1 - Context and analytical framework

This Outlook assumes that the world economy grows on average by 4.4% over the five years to 2015.5 In the longer term, the rate of growth is assumed to temper, as the emerging economies mature and their growth rates converge with those of the OECD economies. World GDP is assumed to grow by an average of 3.2% per year over the period 2008-2035, the same rate as in 1980-2008 (Table 1.3). Growth slows over the projection period, averaging 3.1% per year in the period 2015-2035. The non-OECD countries as a group are assumed to continue to grow much more rapidly than the OECD countries, driving up their share of world GDP. In several leading non-OECD countries, 5. The GDP growth assumptions to 2015 are based primarily on the latest IMF projections from the July 2010 update of its World Economic Outlook (IMF, 2010a), with some adjustments according to more recent information available for the OECD (OECD, 2010) and other countries from national and other sources. The assumptions are the same for eagch scenario, because of the uncertainty surrounding the relationships between policy-driven changes in energy-related investment, the resulting impact on climate change and the pace of economic growth.

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a combination of important macro- and micro-economic reforms, including trade liberalisation, more credible economic management, and regulatory and structural reforms have improved the investment climate and the prospects for strong long-term growth. India overtakes China in the 2020s to become the fastest-growing WEO region, the result of demographic factors and its earlier stage of economic development. India’s growth nonetheless slows from 7.9% in 2008-2015 to 5.9% in 2015-2035. China’s growth rate slows to 4.4% in 2015-2035, less than half the rate at which it has been growing in recent years (and in 2009, when it still grew by 9.1% despite the global recession). Among the OECD regions, North America continues to grow fastest, at 2.2% per year on average over the projection period, buoyed by more rapid growth in its population and labour force, and lower debt than in Europe and the Pacific region.

Energy prices As with any good, the demand for a given energy service depends on the price, which in turn reflects the price of the fuel as well as the technology used to provide it. The price elasticity of demand, i.e. the sensitivity of demand to changes in price, varies across fuels and sectors, and over time, depending on a host of factors, including the scope for substituting the fuel with another or adopting more efficient energy-using equipment, the need for the energy service and the pace of technological change. In each scenario, projections are based on the average retail prices of each fuel used in end uses, power generation and other transformation sectors. These prices are derived from assumptions about the international prices of fossil fuels (Table 1.4), and take account of any taxes, excise duties and carbondioxide emissions penalties (see below), as well as any subsidies. Final electricity prices are derived from marginal power-generation costs (which reflect the price of primary fossil-fuel inputs to generation, and the cost of hydropower, nuclear energy and renewables-based generation) and the non-generation costs of supply. The fossil-fuel-price assumptions reflect our judgment of the prices that will be needed to stimulate sufficient investment in supply to meet projected demand over the projection period.6 Although the price paths follow smooth trends, prices are likely, in reality, to fluctuate.

Having rebounded through much of 2009, international crude oil prices settled into a range of around $70-85 per barrel in the first half of 2010. Prices are assumed to rise steadily over the entire projection period in all but the 450 Scenario, as rising global demand requires the development of increasingly more expensive sources of oil (see Chapter 3). The level of prices needed to match oil supply and demand varies with the degree of policy effort to curb demand growth and differs markedly across the three scenarios. In the New Policies Scenario, the average IEA crude oil import price reaches $105/barrel (in real 2009 dollars) in 2025 and $113/barrel in 2035 (Figure 1.2).7 In nominal terms, prices more than double to $204/barrel in 2035.8 In the Current Policies Scenario, substantially higher prices 6. This methodology differs from that used in the IEA’s Medium Term Oil and Gas Market Report, which assumes the prices prevailing on futures markets (IEA, 2010a). 7. In 2009, the average IEA crude oil import price was $1.52/barrel lower than the first-month forward spot price of West Texas Intermediate (WTI) and $1.27/barrel lower than spot dated Brent. 8. The dollar exchange rates used were those prevailing in 2009 (€0.720 and ¥93.6), which were assumed to remain unchanged over the projection period.

Chapter 1 - Context and analytical framework

69

1

S P O T L I G H T

Does rising prosperity inevitably push up energy needs? That energy use typically rises with incomes is incontrovertible and widely understood. As economies grow, they require more energy to fuel factories and trucks, to heat and cool buildings and to meet growing personal demand for mobility, equipment and electrical appliances. Over the last several decades, energy use has tended to rise proportionately with GDP at the global level and, in most cases, at the national level too, though the relationship is usually less than one to one: in other words, energy needs usually grow somewhat less rapidly in percentage terms than the size of the economy, because of changes in economic structure towards less energy-intensive activities and because of technological change that gradually improves the efficiency of providing energy-related services.

But will this relationship persist far into the future and do rising incomes, therefore, make increased energy use inevitable? This Outlook and previous editions predict that the relationship will indeed remain strong — at least for the next quarter of a century — unless governments intervene to change it, through measures that lead to a shift in behaviour and/or in the way in which energy needs are met. For as long as the global economy continues to expand — and no-one doubts that it will, in the longer term, in the absence of a catastrophic event — and population expands, then the world’s overall energy needs will undoubtedly rise. But just how quickly, and in what way those needs are met, is far from certain. The energy projections in this Outlook — and experience in many countries over the past three decades — show very clearly that the link between GDP and energy use can be loosened, if not entirely broken, through a combination of government action and technological advances. What matters to users of energy, whether they be businesses or individuals, is the ultimate energy-related services that they receive: mobility, heating, cooling or a mechanical process. Today, these services are often provided in ways that involve unnecessarily large amounts of energy, much of it derived from fossil fuels. The technology exists today to increase greatly the efficiency with which those services are provided and that technology will surely continue to improve in the future. The commercial incentives for manufacturers to make available more efficient equipment, appliances and vehicles, and for consumers to buy them, are set to increase with rising energy costs. But commercial factors alone will be not sufficient. Governments need to act to reinforce those incentives so as to encourage even faster improvements in energy efficiency and to discourage energy waste, confident in the environmental, energy-security and broader economic benefits that would follow. Experience has shown what governments can achieve through determined action; our projections show what more can be achieved in the future.

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World Energy Outlook 2010 - GLOBAL ENERGY TRENDS

MBtu

Japan

MBtu

Japan

97.3

9.4

7.4

4.1

60.4

97.3

9.4

7.4

4.1

60.4

112.0

14.0

12.2

8.0

103.6

97.7

12.2

10.6

7.0

90.4

2015

130.6

17.2

14.9

10.4

127.1

101.7

13.4

11.6

8.1

99.0

2020

149.8

20.4

17.8

13.1

151.1

104.1

14.2

12.3

9.1

105.0

2025

170.2

24.0

20.9

15.9

177.3

105.6

14.9

12.9

9.9

110.0

2030

192.4

27.6

24.1

18.9

204.1

106.5

15.3

13.3

10.4

113.0

2035

112.1

14.2

12.3

8.0

107.7

97.8

12.4

10.7

7.0

94.0

2015

135.9

17.8

15.5

10.5

141.3

105.8

13.9

12.1

8.2

110.0

2020

157.6

21.4

18.6

13.3

172.7

109.5

14.9

12.9

9.3

120.0

2025

181.4

25.7

22.4

16.7

209.6

112.5

15.9

13.9

10.4

130.0

2030

Current Policies Scenario

207.8

29.8

26.0

20.3

243.8

115.0

16.5

14.4

11.2

135.0

2035

106.0

13.6

11.9

8.0

100.7

92.5

11.9

10.4

7.0

87.9

2015

110.2

15.6

13.6

10.3

115.6

85.8

12.2

10.6

8.0

90.0

2020

109.0

17.7

15.4

12.8

129.5

75.8

12.3

10.7

8.9

90.0

2025

106.8

20.1

17.5

15.1

145.1

66.3

12.5

10.9

9.4

90.0

2030

450 Scenario

112.1

22.7

19.8

17.5

162.6

62.1

12.6

11.0

9.7

90.0

2035

Note: Natural gas prices are weighted averages, expressed on a gross calorific-value basis. All prices are for bulk supplies exclusive of tax. The US gas import price is used as a proxy for prices prevailing on the domestic market. Nominal prices assume inflation of 2.3% per year from 2009.

are needed to balance supply with the faster growth in demand. The average crude oil price rises more briskly, especially after 2020, reaching $120/barrel in 2025 and $135/barrel ten years later. In the 450 Scenario, by contrast, prices increase more slowly, levelling off at about $90/barrel by 2020, as demand peaks and then begins to decline by around 2015 (see Chapter 15 for details of the drivers of oil demand in this scenario). Falling demand is assumed to outweigh almost entirely the rising cost of production (see Chapter 3). Higher CO2 prices contribute to lower demand and, therefore, lower international prices (see below). In reality, whatever the policy landscape, oil prices are likely to remain volatile.

Traditionally, natural gas prices have moved in fairly close tandem with oil prices, either because of indexation clauses in long-term supply contracts or indirectly through competition between gas and oil products in power generation and end-use markets. In recent years, gas prices have tended to decouple from oil prices, as a result of relatively abundant supplies of unconventional gas in North America, which have driven gas prices there down relative to oil, increased availability of spot supplies of cheaper liquefied natural gas in Europe and Asia-Pacific, and some provisional changes to contractual terms in Europe, which have lessened the role of oil prices and increased the importance of gas-price indexation in long-term contracts. There is considerable uncertainty about whether this tentative move away from oil indexation will prove permanent and, even if it does, whether this will herald an era of lower gas prices relative to oil (see Spotlight in Chapter 5). One uncertainty is the length of time that long-term contracts in bulk gas supply will remain dominant in Europe and Asia-Pacific. Yet, even if direct gas-to-gas competition becomes more widespread and allowing for the fact that the underlying cost drivers for oil and gas differ, the potential for substitution between oil products and gas will ensure that changes in the price of one will continue to affect the price of the other.9 In all three scenarios, the ratio of gas prices to oil prices in North America is assumed to rise modestly through to 2035 as the cost of unconventional gas production rises, but the ratio remains well below the 9. See IEA (2009) for a detailed discussion of the prospects for gas pricing.

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World Energy Outlook 2010 - GLOBAL ENERGY TRENDS

historical average. In Europe and Japan (a proxy for Asia-Pacific), we assume that the ratio of gas prices remains broadly unchanged to 2035 (Figure 1.3). The ratio of gas to oil prices throughout the projection period remains well below the average for the period 1980-2009 in all regions. International steam-coal prices have fallen from record levels attained in mid2008, with the slowdown in demand and weaker prices for gas, the main competitor to coal (especially in the power sector). The price of coal imported by OECD countries averaged slightly over $95 per tonne in 2009. In the New Policies Scenario, coal prices are assumed to remain at about this level in real terms to 2015 and then, with rising demand to 2020 and higher prices of gas to rise to $107/tonne by 2035. Coal prices rise less in percentage terms than oil or gas prices, partly because coal production costs are expected to remain low and because coal demand flattens out by 2020. Coal prices rise more quickly in the Current Policies Scenario on stronger demand growth, but fall in the 450 Scenario, reflecting the impact of policy action to cut demand.

Fuel price divided by oil price

Figure 1.3 z Ratio of average natural gas and coal import prices to crude oil in the New Policies Scenario 1.6

CO2 prices The pricing of carbon emissions could play an increasingly important role in driving energy markets in the long term. For now, only the European Union and New Zealand have adopted formal cap-and-trade schemes, which set caps on carbon-dioxide emissions by the power generation and industry sectors and provide for trading of CO2 certificates, yielding prices of CO2 for specific time periods. Thus, in the Current Policies Scenario, carbon pricing is assumed to be limited to EU countries and to New Zealand. The price of CO2 under the EU Emission Trading System is projected to reach $30/tonne in 2020 and $42/tonne in 2035 (Table 1.5). Chapter 1 - Context and analytical framework

73

1

Table 1.5 z CO2 prices by main region and scenario ($2009 per tonne) Region New Policies

Current Policies 450

2009

2020

2030

2035

22

38

46

50

Japan

n.a.

20

40

50

Other OECD

n.a.

-

40

50

22

30

37

42

OECD+

n.a.

45

105

120

Other Major Economies

n.a.

-

63

90

European Union

European Union

Note: OECD+ includes all the OECD countries plus non-OECD EU countries. The CO2 price in the European Union is assumed to converge with that in OECD+ by 2020 in the 450 Scenario. Other Major Economies comprise Brazil, China, the Middle East, Russia and South Africa.

Carbon pricing is assumed to be adopted in other regions in the New Policies and 450 Scenarios. In the New Policies Scenario, cap-and-trade systems covering the power and industry sectors are assumed to be established in Australia, Japan and Korea as of 2013, and in OECD countries (see note to Table 1.5) after 2020, where it reaches $50/tonne in 2035. In the 450 Scenario, cap-and-trade covering power generation and industry is assumed to start in 2013 in OECD+ and after 2020 in the Other Major Economies category (see note to Table 1.5). In this scenario, we assume that CO2 is traded in these two groups separately. To contain emissions at the levels required in the 450 Scenario, we estimate that the price of CO2 in OECD+ would need to reach $45/tonne in 2020 and $120/tonne in 2035. The price rises to $63/tonne in 2030 and to $90/tonne in 2035 in the Other Major Economies. The prices are set by the most expensive abatement option, for example, carbon capture and storage in industry in the OECD+ in 2035. It is assumed that OECD+ countries have access to international offsets, up to a limit of one-third of total abatement in 2020. Further details of carbon pricing and how it is modelled in the 450 Scenario can be found in Chapter 13.

Technology has an important impact on both the supply and use of energy. Our projections are, therefore, very sensitive to assumptions about developments in technology and how quickly new technologies are deployed. Those assumptions vary for each fuel, each sector and each scenario, according to our assessment of the current stage of technological development and commercialisation and the potential for further improvements and deployment, taking account of economic factors and market conditions.10 Government policies and energy prices have an important impact on the pace of development and deployment of new technologies. As a consequence, more rapid technological advances are seen in the 450 Scenario. In all three scenarios, the performance of currently available categories of technology is assumed to improve on various operational criteria, including energy efficiency, 10. See Energy Technology Perspectives 2010 (IEA, 2010b) for a detailed assessment of the long-term prospects for energy-related technologies.

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World Energy Outlook 2010 - GLOBAL ENERGY TRENDS

practicality, environmental impact and flexibility. But the pace of improvement varies: it is fastest in the 450 Scenario, thanks to the effect of various types of government support, including economic instruments (such as carbon pricing, taxes and subsidies), regulatory measures (such as standards and mandates) and direct public-sector investment. These policies stimulate increased spending on research, development and deployment. Technological change, in general, is slowest in the Current Policies Scenario, because no new public policy actions are assumed. Yet, even in this scenario, significant technological improvements occur, aided by higher energy prices. In the New Policies Scenario, the pace of technological change lies between that in the two other scenarios. Crucially, no completely new technologies on the demand or supply side, beyond those known today, are assumed to be deployed before the end of the projection period, as it cannot be known whether or when such breakthroughs might occur and how quickly they may be commercialised.

The critical factor with respect to energy use concerns how the introduction of more advanced technologies affects the average energy efficiency of equipment, appliances and vehicles in use, and, therefore, the overall intensity of energy consumption (the amount of energy needed to provide one dollar of gross domestic product). Practical and financial constraints on how quickly energy-related capital stock11 can be replaced affect the rate at which new technologies can be introduced and, consequently, the rate of improvement in energy efficiency. Some types of capital stock, such as power stations (which have a long design life), are so costly and difficult to install that they are replaced only after a very long time. Indeed, much of the capital stock in use today falls into this category. As a result, much of the impact of recent and future technological developments that improve energy efficiency will not be felt until towards the end of the projection period. Rates of capital-stock turnover differ greatly: most cars and trucks, heating and cooling systems, and industrial boilers in use today will be replaced by 2035. But most existing buildings, roads, railways and airports, as well as many power stations and refineries will still be in use then, unless strong government incentives and/or a change in market conditions encourage or force early retirement. The extent to which this happens (or the stock is modernised to reduce energy needs) is limited in the Current Policies Scenario; it is greater in the New Policies Scenario and especially in the 450 Scenario. On the supply side, technological advances are assumed to improve the technical and economic efficiency of producing and supplying energy. In some cases, they result in lower unit costs, lead to cleaner ways of producing and delivering energy services, or make available resources that are not recoverable commercially or technically today. Many emerging renewable energy technologies, such as wind and photovoltaic energy, fall into this category. In other cases, where technologies are relatively mature, such as conventional oil and gas drilling, the impact of technological advances on unit costs is expected to be at least partially offset by the rising cost of raw materials and labour. Some major new supply-side technologies that are approaching the 11. Any type of asset that affects the amount and the way in which energy is supplied or used, such as oil wells, power stations, pipelines, buildings, boilers, machinery, appliances and vehicles.

commercialisation phase are assumed to become available and to be deployed to some degree before the end of the projection period. These include carbon capture and storage, advanced biofuels, large-scale concentrating solar power and smart grids. Details about how fast these technologies are deployed can be found in the relevant chapters.

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World Energy Outlook 2010 - GLOBAL ENERGY TRENDS

CHAPTER 2

ENERGY PROJECTIONS TO 2035 Twilight in demand? H

I

G

H

L

I

G

H

T

S

z Global primary energy demand continues to grow in the New Policies Scenario,

but at a slower rate than in recent decades. By 2035, it is 36% higher than in 2008. Non-OECD countries account for 93% of the increase. The OECD share of world demand falls from 44% today to 33% in 2035. Energy demand in the other scenarios diverges over the period: by 2035, it is 8% higher in the Current Policies Scenario and 11% lower in the 450 Scenario than in the New Policies Scenario. z Fossil fuels maintain a central role in the primary energy mix in the New Policies

Scenario, but their share declines, from 81% in 2008 to 74% in 2035. Oil demand is up by 18%, from 84 mb/d in 2009 to 99 mb/d in 2035. Coal demand is around 20% higher in 2035 than today, with almost all of the growth before 2020. The 44% increase in natural gas demand surpasses that for all other fuels due to the favourable environmental and practical attributes of gas. Electricity demand grows by around 80% by 2035, requiring 5 900 GW of total capacity additions. z The importance of China in global energy markets continues to grow. In 2000,

China’s energy demand was half that of the United States, but preliminary data indicate it is now the world’s biggest energy consumer. Growth prospects remain strong, given China’s per-capita energy use is still only one-third of the OECD average and it is the most populous nation. z Investment in energy-supply infrastructure to meet demand to 2035 in the New

Policies Scenario amounts to $33 trillion (in year-2009 dollars). Power sector investment accounts for $16.6 trillion, or just over half of the total. Almost two-thirds of total investment is in non-OECD countries. z The New Policies Scenario implies a persistently high level of spending on

energy imports by many countries. Total spending on oil and gas imports more than doubles from $1.2 trillion in 2010 to $2.6 trillion in 2035. The United States is overtaken by China around 2025 as the world’s biggest spender on oil imports: India overtakes Japan around 2020 as the world’s third-largest spender.

z In the New Policies Scenario, energy-related CO2 emissions rise from 29.3 Gt in

2008 to 35.4 Gt in 2035, consistent with an eventual increase in global average temperature of over 3.5°C. All of the growth in emissions comes from non-OECD countries; emissions in the OECD drop by 20%. Chinese emissions exceed those from the entire OECD by 2035.

Chapter 2 16- Energy - Asean-4 projections country profiles to 2035

77

Overview of energy trends by scenario What governments do to tackle critical energy-related problems holds the key to the outlook for world energy markets over the next quarter of a century. Our projections of energy demand and supply accordingly vary significantly across the three scenarios presented in this Outlook (Box 2.1). In the New Policies Scenario, which takes account of both existing policies and declared intentions, world primary energy demand is projected to increase by 1.2% per year between 2008 and 2035, reaching 16 750 million tonnes of oil equivalent (Mtoe), an increase of 4 500 Mtoe, or 36% (Figure 2.1). Demand increases significantly faster in the Current Policies Scenario, in which no change in government policies is assumed, averaging 1.4% per year over 2008-2035. In the 450 Scenario, in which policies are assumed to be introduced to bring the world onto an energy trajectory that provides a reasonable chance of constraining the average global temperature increase to 2° Celsius, global energy demand still increases between 2008 and 2035, but by a much reduced 22%, or an average of 0.7% per year. Energy prices ensure that projected supply and demand are in balance throughout the Outlook period in each scenario (see Chapter 1).

Fossil fuels remain the dominant energy sources in 2035 in all three scenarios, though their share of the overall primary fuel mix varies markedly, from 62% in the 450 Scenario to 79% in the Current Policies Scenario, compared with 74% in the New Policies Scenario and 81% in 2008 (Table 2.1 and Figure 2.2). These differences reflect the varying strength of policy action assumed to address climate-change and energysecurity concerns. The shares of renewables and nuclear power are correspondingly highest in the 450 Scenario and lowest in the Current Policies Scenario. The range of outcomes — and therefore the uncertainty with respect to future energy use — is largest for coal and non-hydro renewable energy sources. 78

World Energy Outlook 2010 - GLOBAL ENERGY TRENDS

Box 2.1 z Understanding the three WEO-2010 scenarios WEO-2010 presents detailed projections for three scenarios: a New Policies Scenario, a Current Policies Scenario and a 450 Scenario. The scenarios differ with respect to what is assumed about future government policies related to the energy sector. There is much uncertainty about what governments will actually do over the coming quarter of a century, but it is highly likely that they will continue to intervene in energy markets. Indeed, many countries have announced formal objectives; but it is very hard to predict with any degree of certainty what policies and measures will actually be introduced or how successful they will be. The commitments and targets will undoubtedly change in the course of the years to come. Given these uncertainties, we present projections for a Current Policies Scenario as a baseline in which only policies already formally adopted and implemented are taken into account. In addition, we present projections for a New Policies Scenario, which assumes the introduction of new measures (but on a relatively cautious basis) to implement the broad policy commitments that have already been announced, including national pledges to reduce greenhouse-gas emissions and, in certain countries, plans to phase out fossilenergy subsidies. We focus in this Outlook on the results of this New Policies Scenario, while also referring to the outcomes in the other scenarios, in order to provide insights into the achievements and limitations of the important developments that have taken place in international climate and energy policy over the past year.

The 450 Scenario, which was first presented in detail in WEO-2008 and for which updated projections are presented here, sets out an energy pathway consistent with the goal of limiting the global increase in average temperature to 2°C, which would require the concentration of greenhouse gases in the atmosphere to be limited to around 450 parts per million of carbon-dioxide equivalent (ppm CO2-eq). Its trajectory to 2020 is somewhat higher than in WEO-2009, which started from a lower baseline and assumed stronger policy action before 2020. The decline in emissions is, by necessity, correspondingly faster after 2020.

Global energy intensity — the amount of energy needed to generate each unit of GDP — has fallen steadily over the last several decades due to several factors including improvements in energy efficiency, fuel switching and structural changes in the global economy away from energy-intensive industries. The implications for global energy consumption and environmental pollution have been significant: if no improvements in energy intensity had been made between 1980 and 2008, global energy consumption would be 32% higher today, roughly equivalent to the combined current consumption of the United States and the European Union. Chapter 2 - Energy projections to 2035

The policies that are assumed to be introduced in the New Policies and 450 Scenarios have a significant impact on the rate of decline in energy intensity. In the Current Policies Scenario, energy intensity continues to decline gradually over the projection period, but at a much slower rate than in the other scenarios. By 2035, energy intensity declines compared to 2008 are: 28% in the Current Policies Scenario, 34% in the New Policies Scenario and 41% in the 450 Scenario. By comparison, between 1981 and 2008 global energy intensity fell by 23% (Figure 2.3). Over the period 2008 to 2035, the annual average improvement in energy intensity is 1.2% in the Current Policies Scenario, 1.5% in the New Policies Scenario and 1.9% in the 450 Scenario. 80

Energy trends in the New Policies Scenario Primary energy demand In this chapter, we deliberately focus more attention on the results of the New Policies Scenario.1 This is done to provide a clear picture of where planned policies, assumed to be implemented in a cautious way, would take us. As indicated, the New Policies Scenario projects global energy consumption to increase by 36% from 2008 to 2035, rising from 12 300 Mtoe to 16 750 Mtoe (Table 2.2). Growth in demand slows progressively, from an average of 1.4% per year in the period 2008-2020 to 0.9% per year in 2020-2035, as measures introduced to combat climate change and meet energysecurity objectives take effect.

Over the Outlook period, demand for each fuel source increases (Figure 2.4). Fossil fuels (oil, coal and natural gas) account for 53% of the increase in energy demand. They continue to supply the bulk of global energy consumption, though their share falls from 81% in 2008 to 74% in 2035. Rising fossil-energy prices to end-users, resulting from upward price pressures on international markets and increasing costs of carbon, together with policies to encourage energy savings and switching to low-carbon energy sources, help to restrain demand growth for all three fossil fuels. Oil remains the dominant fuel in the primary energy mix during the Outlook period in the New Policies Scenario, with demand increasing from 85 million barrels per day (mb/d) in 2008 (84 mb/d in 2009) to 99 mb/d in 2035. Its share of the primary fuel mix, which stood at 33% in 2008, drops to 28% as high prices lead to further switching away from oil in the industrial and power-generation sectors and opportunities emerge 1. Annex A provides detailed projections of energy demand by fuel, sector and region for all three scenarios.

Chapter 2 - Energy projections to 2035

81

2

to substitute other fuels for oil products in transport. Demand for coal increases from 4 736 million tonnes of coal equivalent (Mtce) in 2008 to just over 5 600 Mtce in 2035, with most of the growth before 2020.2 Growth in demand for natural gas far surpasses that of all other fossil fuels due to its more favourable environmental and practical attributes and constraints on how quickly low-carbon energy technologies can be deployed. Global natural gas consumption increases from 3 149 billion cubic metres (bcm) in 2008 to just above 4 500 bcm in 2035. By the end of the Outlook period, natural gas is close to overtaking coal as the second most important fuel in the primary energy mix. Table 2.2 z World primary energy demand by fuel in the New Policies Scenario (Mtoe) 1980

2008

2015

2020

2030

2035

2008-2035*

Coal

1 792

3 315

3 892

3 966

3 984

3 934

0.6%

Oil

3 107

4 059

4 252

4 346

4 550

4 662

0.5%

Gas

1 234

2 596

2 919

3 132

3 550

3 748

1.4%

Nuclear

186

712

818

968

1 178

1 273

2.2%

Hydro

148

276

331

376

450

476

2.0%

Biomass and waste**

749

1 225

1 385

1 501

1 780

1 957

1.7%

12

89

178

268

521

699

7.9%

7 229

12 271

13 776

14 556

16 014

16 748

1.2%

Other renewables Total

* Compound average annual growth rate. ** Includes traditional and modern uses.

The share of nuclear power increases over the projection period, from 6% in 2008 to 8% in 2035. Government policies are assumed to boost the role of nuclear power in several countries. Furthermore, it is assumed that a growing number of countries implement programmes to extend the lifetime of their currently operating nuclear plants, thereby reducing the capacity that would otherwise be lost to retirement in the period to 2035. The use of modern renewable energy — including wind, solar, geothermal, marine, modern biomass and hydro — triples over the course of the Outlook period, growing from 843 Mtoe in 2008 to just over 2 400 Mtoe in 2035. Its share in total primary energy demand increases from 7% to 14%. Consumption of traditional biomass drops from 746 Mtoe in 2008 to a little over 720 Mtoe in 2035, after a period of modest increase to 2020. Demand for renewable energy increases substantially in all regions, with dramatic growth in some areas, including China and India. Power generation from renewables triples from 2008 to 2035, with its share of the generation mix increasing from 19% in 2008 to 32% in 2035. 2. 1 Mtce is equal to 0.7 Mtoe.

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World Energy Outlook 2010 - GLOBAL ENERGY TRENDS

S P O T L I G H T

2

How do the energy demand projections in WEO-2010 compare with WEO-2009? Though this chapter concentrates on the results of the New Policies Scenario, it is also informative to compare the level of world primary energy demand in this year’s Current Policies Scenario with the results projected in the Reference Scenario of WEO-2009, using a similar methodology. Total primary energy demand in 2015 is 3% higher compared with last year’s projections, but it is less than 1% higher by 2030 (the last year of the projection period in WEO-2009). This small divergence masks important changes among regions: projected demand in OECD countries in 2030 is lower than projected last year, but this is more than offset by higher projected demand in the rest of the world. Projected demand for all fuels, with the exception of oil, is higher in absolute terms in 2030 in this year’s report. The biggest increase is for natural gas, with demand 4.4%, or 192 bcm, higher than projected last year, while global oil demand is 2.4%, or 2.5 mb/d, lower. Compared with the projections in WEO-2009, projected electricity generation this year is essentially unchanged, but there are some notable shifts in the generating mix, with both natural gas and nuclear seeing sizeable increases.

These differences result from the combined effect of many changes. Numerous new policies enacted between mid-2009 and mid-2010, aimed at encouraging a transition to a cleaner, more efficient and more secure energy system, have been incorporated into the Current Policies Scenario and act to dampen growth in projected demand. However, these new policies are insufficient to offset other factors that drive projected demand higher. Most importantly, the global economy appears to be emerging from the economic and financial crisis faster than expected. Therefore, our assumed rate of growth in world GDP — the main driver of energy demand — is now higher than in WEO-2009, particularly in nonOECD countries, which are coming out of the recession more strongly than OECD countries. Compared with the WEO-2009, which assumed a more protracted recovery, the upward revision in GDP plays a key role in boosting demand growth in the early stages of the projection period (hence the big differences between the two scenarios to 2015). Adjustments to the assumptions about energy prices, including changes to relative pricing that affect the energy mix, further explain some of the differences. The price assumptions vary across the different scenarios presented in WEO-2010 in line with the degree of policy effort needed to curb demand growth. In the Current Policies Scenario, higher oil prices are needed (compared with WEO-2009) to choke off demand to bring it into balance with supply, while coal prices also increase slightly. In contrast, natural gas price assumptions have been scaled back, in North America by as much as 10% after 2020, as the substantial rise in unconventional gas production drives prices lower.

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83

This year’s 450 Scenario depicts a somewhat higher trajectory for CO2 emissions to 2020 than in WEO-2009, due to less ambitious action in the early period to curb emissions. This is offset by a faster decline in emissions after 2020. The main reason for the change in trajectory is that the opportunity for concerted, immediate action to slow the growth in emissions was missed as the United Nations climate meeting in Copenhagen in December 2009 did not achieve a comprehensive agreement on limiting emissions of greenhouse gases.

Mtoe

Figure 2.4 z World primary energy demand by fuel in the New Policies Scenario Oil

The faster pace of growth in primary energy demand that has occurred in non-OECD countries over the last several decades is set to continue, reflecting faster rates of growth of population, economic activity, urbanisation and industrial production. In the New Policies Scenario, total non-OECD energy consumption increases by 64% in 20082035, compared with a rise of just 3% in OECD countries. Nonetheless, annual average growth in non-OECD energy demand slows through the Outlook period, from 2.4% in 2008-2020 to 1.4% in 2020-2035. The OECD share of global primary energy demand, which declined from 61% in 1973 to 44% in 2008, falls to just 33% in 2035 (Table 2.3). The increase in non-OECD energy consumption is led by brisk growth in China, where primary demand surges by 75% in 2008-2035, a far bigger increase than in any other country or region (Figure 2.5). China accounts for 36% of the global increase in primary energy use between 2008 and 2035, with its share of total demand jumping from 17% to 22%. India is the second-largest contributor to the increase in global demand to 2035, accounting for 18% of the rise. India’s energy consumption more than doubles by that date, growing on average by 3.1% per year, a rate of growth significantly higher than in any other region. Outside Asia, the Middle East experiences the fastest rate of 84

World Energy Outlook 2010 - GLOBAL ENERGY TRENDS

increase, at 2.0% per year. After a modest increase to 2020, aggregate energy demand in OECD countries stagnates. Nonetheless, by 2035 the United States is still the world’s second-largest energy consumer, well ahead of India, which is a distant third. Table 2.3 z Primary energy demand by region in the New Policies Scenario (Mtoe) 1980

2000

2008

2015

2020

2030

2035

2008-2035*

OECD

4 050

5 233

5 421

5 468

5 516

5 578

5 594

0.1%

North America

2 092

2 670

2 731

2 759

2 789

2 836

2 846

0.2%

United States

1 802

2 270

2 281

2 280

2 290

2 288

2 272

-0.0%

Europe

1 493

1 734

1 820

1 802

1 813

1 826

1 843

0.0%

Pacific

464

829

870

908

914

916

905

0.1%

Japan

345

519

496

495

491

482

470

-0.2%

Non-OECD

3 003

4 531

6 516

7 952

8 660

10 002

10 690

1.9%

E.Europe/Eurasia

1 242

1 019

1 151

1 207

1 254

1 344

1 386

0.7%

Caspian

n.a

128

169

205

220

241

247

1.4%

Russia

n.a

620

688

710

735

781

805

0.6%

1 067

2 172

3 545

4 609

5 104

6 038

6 540

2.3%

China

603

1 107

2 131

2 887

3 159

3 568

3 737

2.1%

India

208

459

620

778

904

1 204

1 405

3.1%

128

381

596

735

798

940

1 006

2.0%

Asia

Middle East Africa

274

502

655

735

781

868

904

1.2%

Latin America

292

456

569

667

723

812

855

1.5%

Brazil

114

185

245

301

336

386

411

1.9%

World**

7 229

10 031

12 271

13 776

14 556

16 014

16 748

1.2%

n.a

1 682

1 749

1 722

1 723

1 719

1 732

-0.0%

European Union

* Compound average annual growth rate. ** World includes international marine and aviation bunkers (not included in regional totals).

Figure 2.5 z World primary energy demand by region in the New Policies Scenario 18 000

China

16 000

United States

14 000

European Union

12 000

India

10 000

Middle East

8 000

Japan

6 000

Inter-regional (bunkers)

4 000

Rest of world

2 000 0 1990

1995

2000

2005

Chapter 2 - Energy projections to 2035

2010

2015

2020

2025

2030

2035

85

2

Non-OECD countries generate the bulk of the increase in global demand for all primary energy sources (Figure 2.6). OECD oil demand falls by 6 mb/d in 2009-2035, but this is offset by a 19-mb/d increase in the non-OECD (international bunker demand also rises by almost 3 mb/d). Oil demand increases the most in China (7.1 mb/d), India (4.5 mb/d) and the Middle East (2.7 mb/d) as a consequence of rapid economic growth and, in the case of the Middle East, the continuation of subsidies on oil products. By 2035, China overtakes the United States to become the largest oil consumer in the world. Having reached a peak of 46 mb/d in 2005, oil demand in the OECD continues to decline, reaching 35 mb/d in 2035, due to further efficiency gains in transport and continued switching away from oil in other sectors. Oil demand in the United States declines from 17.8 mb/d in 2009 to 14.9 mb/d in 2035. Non-OECD regions are responsible for the entire net increase in coal demand to 2035. China alone accounts for 54% of the net increase; although coal’s share of China’s energy mix continues to decline, more than half of its energy needs in 2035 are still met by coal. Most of the rest of the growth in coal demand comes from India and other nonOECD Asian countries. Driven by policies to limit or reduce CO2 emissions, coal use falls sharply in each of the OECD regions, particularly after 2020. By 2035, OECD countries consume 37% less coal than today. Unlike demand for the other fossil fuels, demand for natural gas increases in the OECD. where it remains the leading fuel for power generation and an important fuel in the industrial, service and residential sectors. Collectively, the OECD countries account for 16% of the growth in natural gas consumption to 2035. Developing Asia, again led by China and India, accounts for 43% of the incremental demand, as gas use increases rapidly in the power sector and in industry. The Middle East, which holds a considerable share of the world’s proven natural gas reserves, is responsible for one-fifth of the global increase in gas consumption.

Preliminary data suggest that China overtook the United States in 2009 to become the world’s largest energy user. This comes just two years after China overtook the United States as the world’s largest emitter of energy-related CO2. Preliminary IEA data, which align closely with those of most of the other main sources of international energy statistics, indicate that in 2009 China consumed about 4% more energy than the United States. China’s emergence as the world’s largest energy consumer is not a surprise. Its phenomenal rate of demand growth over the last decade meant it was destined to become the top energy consumer. This has occurred slightly earlier than expected, however, because of China’s continuing strong economic performance and its quick recovery from the global financial crisis compared to the United States. Since 2000, China’s energy demand has doubled. Growth prospects remain robust considering the country’s low per-capita consumption levels (it is still only around one-third of the average in OECD countries), and the fact that China is the most populous nation on the planet, with more than 1.3 billion people. Today, energy demand in China would be even higher had it not made remarkable progress in reducing its energy intensity (the energy input required per dollar of output). In 2009, China consumed about one-quarter of the energy per unit of economic output than it did in 1980. China has also become a world leader in renewable energy and is pursuing a 10-year programme aimed at boosting the share of low-carbon energy to 15% of total consumption by 2020 and meeting ongoing carbon emissions reduction targets. These efforts are being backed by a development plan entailing planned investment of 5 trillion yuan (approximately $735 billion) in nuclear, wind, solar and biomass projects. Given the sheer scale of China’s domestic market, its push to increase the share of new low-carbon energy technologies (both on the supply side and the demand side, such as advanced vehicle technologies) could play an important role in driving down their costs by contributing to improvements in technology learning rates.

Under the assumptions of the New Policies Scenario, nuclear power expands in both OECD and non-OECD regions between 2008 and 2035, the increase in the non-OECD being almost twice as big in absolute terms. The increase in nuclear power generation in China alone (215 Mtoe) exceeds that of the entire OECD (198 Mtoe). Within the OECD, Japan, Korea, France and the United States are responsible for almost all of the growth. In aggregate, the supply of nuclear power in OECD Europe remains flat. This is consistent with the general assumptions for the New Policies Scenario, in which countries with declared plans to discontinue their nuclear programmes are assumed to pursue them. Non-OECD countries account for 56% of the global increase in the use of non-hydro renewable energy between 2008 and 2035. Biomass, mostly fuel wood, crop residues and charcoal for cooking and heating, represents 38% of incremental energy demand Chapter 2 - Energy projections to 2035

87

in Africa (see Chapter 8). Demand for biomass and waste, consumed mostly in modern applications in power generation and transport, also increases rapidly in the OECD. Non-OECD countries account for almost 90% of the increase in hydropower generation, as considerable potential exists, particularly in Asia and Latin America. By contrast, in the OECD the most suitable sites, especially for large hydro, have already been developed.

Sectoral trends The power sector (which includes both heat and electricity generation) accounts for 53% of the increase in global primary energy demand in 2008-2035. Its share of the primary mix reaches 42% in 2035, compared with 38% in 2008. Total capacity additions of 5 900 GW are required in 2008-2035, or around six times current US capacity. Coal remains the leading fuel for power generation, although its share of total power output peaks at about 42% soon after 2010, and declines to 32% in 2035. This declining coal share benefits non-hydro renewables (including biomass and waste) as their share increases from 3% to 16% by 2035. The shares of total power output of natural gas (21%), nuclear (14%) and hydro (16%) remain relatively constant throughout the Outlook period, while the share of oil continues to decline, to less than 2% in 2035. Total final consumption3 is projected to grow by 1.2% per year throughout the Outlook period (Figure 2.7). Industry demand grows most rapidly, at 1.4% per year, having overtaken transport in 2008 to once again become the second-largest final-use sector, after the buildings sector. By 2035, the industrial sector consumes around 30% of the world’s total final energy consumption. Over three-fifths of the growth in industrial energy demand comes from China and India, while the Middle East and Latin America also see strong growth in demand. OECD industrial energy demand increases through to 2020 before dropping back to levels similar to today by the end of the Outlook period. In aggregate, growth in global transport energy demand averages 1.3% per year in 2008-2035. This is a sharp decline in the rate of growth observed over the last several decades, thanks largely to measures to improve fuel economy. Transport’s share of total final consumption remains flat at around 27% through the Outlook period. All of the growth in transport demand comes from non-OECD regions and inter-regional bunkers; transport energy demand declines slightly in the OECD. Although biofuels, and, to a lesser extent, electricity for plug-in hybrid and electric vehicles take an increasing share of the market for road-transport fuels, oil-based fuels continue to dominate transport energy demand.

In the buildings sector, energy use grows at an average rate of 1.0% per year through the Outlook period. The sector’s share of total final energy consumption remains at around one-third throughout the period to 2035. Electricity consumption is projected to increase at an annual average rate of 2.2% in the period 2008-2035, resulting in overall growth of around 80%. Electricity’s share of total final consumption grows from 17% to 23%. More than 80% of the growth in 3. Total final consumption includes total energy delivered to end-users to undertake activities in industry, transport, agriculture, buildings (including residential and services) and non-energy use.

88

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electricity demand takes place in non-OECD countries as a result of increased demand for household appliances and industrial and commercial electrical equipment, in line with rising prosperity. The shares of biomass and natural gas in total final consumption remain essentially constant through to 2035, while those for oil and coal decline, principally to the benefit of electricity. Figure 2.7 z Incremental energy demand by sector and region in the New Policies Scenario, 2008-2035 OECD

Even though emerging economies experience markedly higher growth in energy demand during the Outlook period, a significant gulf still exists between rich and poor countries in the amount of energy used per capita. Today, the average per-capita energy consumption for the world as a whole is 1.8 tonnes of oil equivalent (toe) per year, but, in most cases, there is a great difference between developing and developed countries. There are also significant variations between countries at similar stages of economic development. Per-capita consumption in Japan, for example, is around half that of the United States. Per-capita global energy consumption rises at 0.3% per year, on average, over the projection period (one-third of the rate experienced since 1995) reaching 2 toe in 2035. Large geographical discrepancies in energy consumption remain. In 2035, the average per-capita level in the OECD, despite having already peaked and now being in steady decline, is still more than twice the global average (Figure 2.8). The most rapid increase in per-capita consumption is in India, but at 1.0 toe in 2035, use per capita is still less than one-quarter that of the OECD. Although China’s per-capita energy consumption is currently below the world average, in 2035 it is 40% higher than today’s global average (or 30% higher than the 2035 global average), thanks to strong economic growth and relatively slow population growth. By 2035, Russia has the world’s highest per-capita energy consumption, at 6.4 toe. This results from the combination of a harsh climate, continuing population decline, the importance of heavy industry in the economy Chapter 2 - Energy projections to 2035

89

2

and relatively inefficient energy production and consumption practices (a legacy of the Soviet era). Per-capita consumption remains lowest in sub-Saharan Africa at only 0.4 toe in 2035, down 23% from 2008 and only one-twelfth of the average OECD percapita consumption. This trend results from sub-Saharan Africa’s rapid population growth and the shift from traditional to modern energy, which is used more efficiently. Figure 2.8 z Per-capita primary energy demand by region as a percentage of 2008 world average in the New Policies Scenario Africa

2008

India

2035

Other Asia

World average 2008

Latin America

World average 2035

China Middle East European Union Japan United States Russia 0%

50%

100%

150%

200%

250%

300%

350%

400%

450%

As with per-capita energy consumption, large differences in energy intensity exist among countries, primarily due to differences in energy efficiency, economic structure and climate. In most cases, non-OECD countries have much higher levels of energy intensity than those of the OECD, but they are also experiencing much faster reductions. Energy intensity in the OECD declines at 1.6% per year between 2008 and 2035, while the rate of decline in the non-OECD is 2.5% (Figure 2.9). China achieves the strongest improvement in its energy intensity at 3.3% per year on average, reaching 0.18 toe per thousand dollars of GDP at market exchange rates (MER) in 2035.

Figure 2.9 z Energy intensity in selected countries and regions in the New Policies Scenario

90

1.2

Russia India

1.0

China

0.8

World OECD

0.6 0.4 0.2 0 1990

1995

2000

2005

2010

2015

2020

2025

2030

2035

World Energy Outlook 2010 - GLOBAL ENERGY TRENDS

Energy production and trade Resources and production prospects4

2

Estimates of the world’s total endowment of economically exploitable fossil fuels and hydroelectric, uranium and renewable energy resources indicate that they are more than sufficient to meet the projected increase in consumption to 2035. There is, however, some uncertainty about whether energy projects will be developed quickly enough to bring these resources to market in a timely manner, as many factors may act to defer investment spending. These include uncertainty about the economic outlook, developments in climate change and other environmental policies, depletion policies in key producing regions and changes to legal, fiscal and regulatory regimes.

Coal is the world’s most abundant fossil fuel by far, with proven reserves of 1 000 billion tonnes (BGR, 2009). At present coal production levels, reserves would meet demand for almost 150 years. Remaining recoverable resources are even larger and a resource shortage is unlikely to constrain coal production. Coal is also the most widely distributed of fossil-fuel resources, with 43% of proven reserves in OECD countries, compared to natural gas (10%) and oil (16%). Proven reserves of oil amounted to 1.35 trillion barrels at the end of 2009, or 46 years production at current levels (O&GJ, 2010). Other economically recoverable resources that are expected to be found will support rising production. Today, proven gas reserves, at around 60 years of current production, far exceed the volume needed to satisfy demand to 2035 and undiscovered conventional gas resources are also sizeable. Moreover, there is huge potential to increase supply from unconventional resources of both oil and gas. Although these resources are generally more costly to exploit, rising fossil-fuel prices throughout the Outlook period and advances in technology and extraction methods are set to make them increasingly important sources of supply. Resources of uranium, the raw material for nuclear fuel, are sufficient to fuel the world’s nuclear reactors at current consumption rates for at least a century (NEA and IAEA, 2009). Significant potential also remains for expanding energy production from hydropower, biomass and other renewable sources (see Chapters 9). In the New Policies Scenario, non-OECD regions account for all of the net increase in aggregate fossil-fuel production between 2009 and 2035 (Figure 2.10). The world’s total oil production reaches 96 mb/d by 2035. Total non-OPEC oil production peaks before 2015 at around 48 mb/d and falls to 46 mb/d by the end of the Outlook period. By contrast, OPEC oil production continues to grow, pushing up the group’s share of world production from 41% in 2009 to 52% in 2035. Projected global gas production in 2035 in the New Policies Scenario increases by 43% compared with 2008. Non-OECD countries collectively account for almost all of the projected increase in global natural gas production in 2008-2035. The Middle East, with the largest reserves and lowest production costs, sees the biggest increase in absolute terms, though Eurasia remains the largest producing region and Russia the single biggest producer. Coal production is projected to rise by 15% between 2008 and 2035. All of the growth comes from

4. Resource and production prospects for each fuel are discussed in more detail in later chapters.

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91

non-OECD countries, with production in the OECD falling by more than one-quarter. China sees the biggest increase in coal output in absolute terms, although the rate of increase in production is much higher in both India and Indonesia.

Mtoe

Figure 2.10 z World incremental fossil-fuel production in the New Policies Scenario, 2008-2035 1 200

OECD

1 000

Non-OECD

800 600 400 200 0 –200 –400

Coal

Oil

Gas

Inter-regional trade The New Policies Scenario sees growing international trade in energy, due to the regional mismatch between the location of demand and production. The share of global oil consumption traded between WEO regions reaches 49% in 2035, compared with 44% today. In absolute terms, net trade rises from 37 mb/d in 2009 to 48 mb/d in 2035. Net imports into the OECD increase slightly to 2015, before gradually falling as OECD oil production declines at a slower rate than the fall in its demand, reducing the need for imports. By 2035, the OECD in aggregate is importing almost 18 mb/d, compared with 23 mb/d in 2009. Developing Asia, led by China and India, sees the biggest jump in oil imports in absolute terms. China’s imports rise from 4.3 mb/d in 2009 to close to 13 mb/d by 2035; India’s jump from 2.2 mb/d to 6.7 mb/d. Total oil exports from the Middle East continue to grow steadily, with the region’s share of global trade increasing from 50% today to 60% in 2035.

Inter-regional natural gas trade rises from 670 bcm in 2008 to around 1 200 bcm in 2035, an increase of 77%. Developing Asia, led by China and India, is responsible for the bulk of the increase in gas imports. Of the OECD regions, Europe sees by the far the biggest increase in reliance on imports. International trade in hard coal among WEO regions is projected to rise from 728 Mtce today to just under 870 Mtce before 2020, before decreasing to settle at a level around 840 Mtce as global demand for coal stabilises over the second half of the projection period. Over the course of the Outlook period demand for increased imports of coal into non-OECD Asia is offset by a sharp drop in demand for imports into OECD Europe, Japan and Korea. By 2035, inter-regional trade meets 15% of global hard coal demand, a level similar to today. 92

World Energy Outlook 2010 - GLOBAL ENERGY TRENDS

Spending on imports Even with the measures that are assumed to be introduced to cut growth in energy demand, the New Policies Scenario implies a persistently high level of spending on oil and gas imports by many importing countries (Figure 2.11). India’s projected spending is highest as a proportion of GDP, reaching 5.1% of GDP at market exchange rates by 2035, followed by China’s at 3.1%. In aggregate, spending in the OECD as a proportion of GDP is set to decline through the Outlook period with the fall in the volume of its imports. Figure 2.11 z Expenditure on net imports of oil and gas as a share of real GDP in the New Policies Scenario 8%

India

7%

China

6%

Japan European Union

5%

United States

4% 3% 2% 1% 0% 1980

1990

2000

2010

2020

2030

2035

Note: GDP is measured at market exchange rates (MER).

Annual expenditure on oil and gas imports in dollar terms continues to increase throughout the Outlook period in most importing countries. Total expenditure at the global level on oil and gas imports more than doubles, from approximately $1.2 trillion in 2010 to $2.6 trillion in 2035, with the share of natural gas in total spending steadily increasing. On a country basis, China overtakes the United States around 2025 to become the world’s biggest spender on oil imports, while India overtakes Japan around 2020 to become the world’s third-largest spender. By 2025, China also surpasses Japan to become the world’s biggest spender on natural gas imports.

Investment in energy-supply infrastructure Cumulative investment of $33 trillion (year-2009 dollars) over 2010-2035 is needed in energy-supply infrastructure in the New Policies Scenario (Table 2.4). The projected investment is equal to around 1.4% of global GDP on average to 2035. This investment enables the replacement of reserves and production facilities that are retired, as well as the expansion of production and transport capacity to meet demand growth. The projected investment does not include demand-side investments, such as expenditure on purchasing cars, air conditioners, refrigerators, etc. Chapter 2 - Energy projections to 2035

93

2

Although aggregate energy demand in OECD countries only increases by 3%, they require 35% of the projected investment (Figure 2.12). This disproportionally high share results from several factors, including the OECD need to retire and replace significant amounts of ageing energy infrastructure, its more capital-intensive energy mix and the higher average unit costs of its capacity additions. Almost 64% of total energy investment will take place in non-OECD countries, where production and demand are expected to increase most. China alone will need to invest $5.1 trillion, or 16% of the world total. The energy mix in the New Policies Scenario has a higher share of energy technologies that are more capital intensive than those adopted in the WEO-2009 Reference Scenario. This factor, together with the extension of the period to 2035, more than offsets the lower rate of projected energy demand, leading to an investment requirement which is some $150 billion higher per year on average over the projection period. Table 2.4 z Cumulative investment in energy-supply infrastructure in the New Policies Scenario, 2010-2035 (billion $ in year-2009 dollars) Coal

The power sector requires $16.6 trillion or 51% of the total energy-supply investment projected to 2035 in the New Policies Scenario. If the investments in the oil, gas and coal industries that are needed to supply fuel to power stations are included, the share increases to 62%. Expenditures to develop transmission and distribution systems account for 42% of the total investment in the electricity industry, with the remainder going to power generation. 94

World Energy Outlook 2010 - GLOBAL ENERGY TRENDS

Investment to meet projected demand for oil in 2010-2035 amounts to $8.1 trillion, or one-quarter of total energy investment. The upstream oil sector accounts for 85% of the total, with the rest needed in downstream oil activities. Capital spending gradually declines over the course of the Outlook period, in line with the slowdown in global oil demand growth and as production shifts increasingly to lower-cost regions. On an annual average basis, investment is $310 billion per year. Investment in the OECD is high relative to its production capacity because unit costs are higher than other regions, particularly in the upstream segment of the supply chain. Figure 2.12 z Cumulative investment in energy-supply infrastructure by region and fuel in the New Policies Scenario, 2010-2035 Power

Cumulative investment in the natural gas supply chain in 2010-2035 is projected at $7.1 trillion, slightly less than for oil. Annual expenditures will increase over time with the increase in demand. Exploration and development of gas fields, including bringing new fields on stream and sustaining output at existing fields, will absorb 64% of total gas investment. In the period 2010-2035, some $720 billion needs to be invested in the coal sector, or 2% of total energy investment. Investment in production of coal is much less capital-intensive than investment in oil or natural gas.

Energy-related CO2 emissions in the New Policies Scenario Rising demand for fossil fuels continues to drive up energy-related carbon dioxide (CO2) emissions through the projection period (Figure 2.13). Additional government policies that are assumed to be adopted, including action to implement pledges to reduce greenhouse-gas emissions announced under the Copenhagen Accord and moves to phase out fossil-energy subsidies in certain regions, help to slow the rate of growth in emissions, but do not stop the increase. Global energy-related CO2 emissions jump by 21% between 2008 and 2035, from 29.3 gigatonnes (Gt) to 35.4 (Gt). Nonetheless, the average rate of growth of 0.7% per year represents a notable improvement on the Current Policies Scenario, in which emissions grow at 1.4% per year on average, reaching 42.6 Gt in 2035. Chapter 2 - Energy projections to 2035

95

2

Gt

Figure 2.13 z World energy-related CO2 emissions by fuel in the New Policies Scenario 40

Gas

35

Oil

30

Coal

25 20 15 10 5 0 1980

1990

2000

2010

2020

2030

2035

Non-OECD countries account for all of the projected growth in energy-related CO2 emissions to 2035 in each of the three scenarios. In the New Policies Scenario, emissions from non-OECD countries continue to rise steadily and are 53% higher in 2035 than today. By 2035, non-OECD energy-related emissions of CO2 are nearly two-and-a-half times those of the OECD. By the end of the Outlook period, emissions from China alone slightly exceed those from the OECD as a whole. All sectors contribute to overall growth in CO2 emissions in 2008-2035: at 2.2 Gt, transport adds the largest amount (and has the highest growth rate), while power generation accounts for a rise of 1.8 Gt.

Energy-related CO2 emissions in the OECD peak before 2015 and decline to 11.8 Gt in 2020, 7% above 1990 levels. OECD countries finance almost 500 million tonnes (Mt) of reductions in non-Annex I countries through purchases of offset emissions credits to comply with their own targets. Direct financing from OECD countries to non-OECD countries is also provided, in order to assist with low-carbon technology investment and to achieve additional abatement. Given the assumption that OECD countries step up domestic abatement efforts after 2020, OECD emissions steadily decline to 10 Gt in 2035. Energy-related CO2 emissions in non-OECD countries are projected to grow from 15.7 Gt in 2008 to 20.8 Gt by 2020 and 24 Gt by 2035. This increase occurs despite the assumed implementation of measures in China and India to significantly reduce their energy intensity, as well as policies in Indonesia, Brazil and South Africa to improve upon the business-as-usual situation (see Chapter 13 for a discussion of the uncertainty around non-Annex I targets). The low end of the intensity improvement targets set by China and India are achieved in the Current Policies Scenario through measures already enacted. This means that in the New Policies Scenario, these targets are exceeded, though much of the additional effort is assumed to be supported through an international offset mechanism or direct finance. With respect to domesticallyfinanced actions, non-OECD countries are assumed to maintain the same level of effort to combat climate change over the projection period. While the projection for greenhouse-gas emissions in the New Policies Scenario is a marked improvement on current trends, much more would need to be done to realise 96

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the Copenhagen Accord objective of limiting the average rise in global temperature to 2°C. The New Policies Scenario puts the world onto a trajectory consistent with stabilising the concentration of greenhouse gases at just over 650 ppm CO2-eq, resulting in a likely temperature rise of over 3.5°C in the long term (see Chapter 13). Energy-related CO2 emissions by fuel exhibit a broadly similar pattern to that of fuel demand, in that the share of oil and coal falls across the period, while the share of gas increases. In 2008, coal had the largest share of total emissions, at 43%, with oil at 37% and gas at 20%. In 2035, this order remains the same in the New Policies Scenario, though the share of coal falls to 41% and that of oil to 36%, while the share of gas increases to 24%. Emissions from bunker fuels change by less than half a percentage point from 2008 to 2035, accounting for 3.5% of emissions in 2008 and 4.0% in 2035. World CO2 emissions per capita have been increasing sharply since 2000. In the New Policies Scenario, this upward trend continues until they reach a peak of 4.5 tonnes around 2015 and then decline to less than 4.2 tonnes by the end of the Outlook period. Large discrepancies remain between regions. Although average per capita emissions continue to fall in the OECD, by 2035 they are still 1.7 times the current global average (Figure 2.14). The fastest growth in per-capita emissions occurs in China; from 4.9 tonnes in 2008, they grow by 41% to 6.9 tonnes in 2035. Africa’s percapita emissions decline through the Outlook period, reaching less than one-sixth of the world average in 2035. Figure 2.14 z Per-capita energy-related CO2 emissions by region as a percentage of 2008 world average in the New Policies Scenario 2008

The crucial role of China in global energy markets The increase in China’s energy consumption between 2000 and 2008 was more than four times greater than in the previous decade. The prospects for further growth remain very strong: energy demand per capita in China is still only 35% of the OECD average. Future developments in China’s energy system, therefore, have major implications for global Chapter 2 - Energy projections to 2035

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supply and demand trends for oil, natural gas and coal, as well as the prospects for limiting climate change. Consequently, the global energy projections in this Outlook remain highly sensitive to the underlying assumptions for the key variables that drive energy demand in China. These include prospects for economic growth, changes in economic structure, developments in energy and environmental policies and the rate of urbanisation. The rapid expansion in China’s energy demand since 2000 is the result of extremely rapid GDP growth and a structural shift in its economy towards energy-intensive heavy industry and exports, especially following its accession to the World Trade Organization in 2001. China now accounts for 28% of global industrial energy demand, a sharp increase on its 16% share in 2000. The rising share of industry in China’s economy led to an increase in the country’s energy intensity. China’s energy intensity increased on average by 2.5% per year between 2002 and 2005, reversing average gains of 6.4% per year between 1990 and 2002. Recognising the adverse implications of rising energy intensity on the economy and energy security, China’s 11th Five-Year Plan set a target to reduce energy intensity by 20% between 2005 and 2010. Government reports indicate that the country’s energy intensity fell by 15.6% from 2005 to 2009 but then edged up slightly in early 2010 (NBS, 2010), suggesting that it will be difficult to achieve the full 20% target. Nonetheless, gains realised over such a short period of time represent a very impressive achievement.

The momentum of economic development looks set to generate strong growth in energy demand in China throughout the Outlook period. In the New Policies Scenario, China’s primary energy demand is projected to climb by 2.1% per year between 2008 and 2035, reaching two-thirds of the level of consumption of the entire OECD (Figure 2.15). China’s total final energy consumption increases at a similar rate, expanding by 2.0% per year between 2008 and 2035. In absolute terms, industry accounts for the single biggest element in the growth in final energy demand. Industry’s share declines marginally, however, as demand is increasingly driven by domestic consumption. This reflects the emergence of a sizeable middle class whose aspirations for modern lifestyles and comfort levels creates a surge in demand for motor vehicles, electrical appliances and other energy-using equipment. China’s electricity demand is projected to almost triple in 2008-2035, requiring capacity additions equivalent to 1.5 times the current installed capacity of the United States. During much of the period of its economic expansion, China was able to meet all of its energy needs from domestic production. A growing share is now being met by imports. China has extensive coal resources, but in recent years has become a net importer. It has struggled to expand its mining and rail-transport infrastructure quickly enough to move coal from its vast inland reserves to the prosperous coastal areas where demand has been growing most rapidly. In the New Policies Scenario, China’s net imports of coal increase to 2015, but the country once again becomes a net exporter towards the end of the Outlook period. Its oil imports jump from 4.3 mb/d in 2009 to 12.8 mb/d in 2035, the share of imports in demand rising from 53% to 84%. Natural gas imports also increase substantially to reach a share of 53% of demand in 2035, requiring a major expansion of pipeline and liquefied natural gas (LNG) regasification infrastructure. 98

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6 000

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The projected rise in China’s energy demand has implications for the local and global environment. In the New Policies Scenario, 58% of the global increase in CO2 emissions to 2035 comes from China alone (Figure 2.16). China’s emissions increase by 54%, to 10.1 Gt, surpassing the emissions from the entire OECD by 2035. One contribution to the strong increase in China’s emissions is that as it has become the world’s biggest export manufacturer, and given its significant reliance on fossil energy, a proportion of its emissions are caused by the manufacturing of goods for export to other countries. This “embedded carbon” far outweighs the carbon embedded in its imports.

Although China’s per-capita emissions are much lower than those in most industrialised countries, they are increasing rapidly. China already emits 12% more per capita than the global average and is set to overtake the per-capita level of the European Union soon after 2020 in the New Policies Scenario. China is currently one Chapter 2 - Energy projections to 2035

of the world’s highest emitters of CO2 per unit of GDP, but our projections indicate an improvement in emissions intensity (3.8% per year) between 2008 and 2035, which is faster than improvements achieved elsewhere.

demand and emissions. In the Current Policies and New Policies Scenarios, global primary oil use increases in absolute terms between 2009 and 2035, driven by population and economic growth, but demand falls in the 450 Scenario in response to radical policy action to curb fossil-fuel use. z The prices needed to balance the oil market differ markedly across the three

scenarios — reflecting the growing insensitivity of demand and supply to price. In the New Policies Scenario, the average IEA crude oil import price (in year-2009 dollars) reaches $113/barrel in 2035. In the Current Policies Scenario, much higher prices — reaching $135/barrel in 2035 — are needed to bring demand into balance with supply. Prices in the 450 Scenario are much lower, as demand peaks before 2020 and then falls. The weaker the response to the climate challenge, the greater the risk of oil scarcity and the higher the economic cost for consuming countries. z In the New Policies Scenario, demand continues to grow steadily, reaching about

99 mb/d (excluding biofuels) by 2035 — 15 mb/d higher than in 2009. All of the growth comes from non-OECD countries, 57% from China alone, mainly driven by rising use of transport fuels; demand in the OECD falls by over 6 mb/d. z Global oil production reaches 96 mb/d in the New Policies Scenario, the

balance of 3 mb/d coming from processing gains. Crude oil output reaches a plateau of around 68-69 mb/d by 2020 — marginally below the all-time peak of about 70 mb/d reached in 2006, while production of natural gas liquids and unconventional oil grows strongly. z Total OPEC production rises continually through to 2035 in the New Policies

Scenario, its share of global output increasing from 41% to 52%. Total non-OPEC oil production is broadly constant to around 2025, as rising production of NGLs and unconventional production offsets a fall in that of crude oil; thereafter, production starts to drop. Increased dependence on a small number of producing countries would intensify concerns about their influence over prices.

z Worldwide upstream oil investment is set to bounce back in 2010, but will

not recover all of the ground lost in 2009, when lower oil prices and financing difficulties led oil companies to slash spending. Upstream capital spending on both oil and gas is budgeted to rise by around 9% to about $470 billion in 2010; it fell by 15% in 2009. Projected oil supply in the New Policies Scenario calls for cumulative investment along the entire oil-supply chain of $8 trillion (in year-2009 dollars) in 2010-2035.

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Demand Primary oil demand trends The global outlook for oil remains highly sensitive to policy action to curb rising demand and emissions, especially in the developing world. In the Current Policies and New Policies Scenarios, global primary oil use increases in absolute terms between 2009 and 2035, driven by population and economic growth, but demand falls in the 450 Scenario in response to the counter-balancing effects of radical policy action to curb fossilenergy use (Figure 3.1). The global economic recovery is expected to drive oil demand back up, following two consecutive years of decline in 2008 and 2009 that resulted from previously surging oil prices and the subsequent global financial and economic crisis.1 Nonetheless, the effect of the recession on demand was slightly less than was expected in last year’s Outlook: global demand bottomed out at an estimated 84 million barrels per day (mb/d) in 2009 — 1 mb/d down on 2008. The share of oil in total primary energy demand is nonetheless projected to fall progressively in each scenario, most sharply in the 450 Scenario, where it reaches 26% in 2035 — down from 33% in 2009. In the New Policies Scenario, the share falls to 28%.

There are big differences in the trajectory of oil demand across the three scenarios. In the New Policies Scenario, demand continues to grow steadily, reaching about 99 mb/d by 2035 — a level that is still 15 mb/d higher than in 2009. A combination of policy action to promote more efficient oil use and switching to other fuels and higher prices (resulting from price rises on international markets, reduced subsidies in some major consuming countries and increased taxes on oil products) partially offsets growing demand for mobility, especially in non-OECD countries. In the Current Policies 1. Preliminary data on oil demand are available for 2009. Because of methodological differences, the oil projections in this report are not directly comparable with those published in the IEA’s monthly Oil Market Report or annual Medium Term Oil and Gas Market Report.

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Scenario, oil demand rises more quickly through to 2035, reaching about 107 mb/d. In the 450 Scenario, demand reaches a peak of about 88 mb/d soon after 2015 and then falls steadily to about 81 mb/d by 2035 — 3 mb/d down on the 2009 level.

* Excludes biofuels demand, which is projected to rise from 1.1 mb/d (in energy-equivalent volumes of gasoline and diesel) in 2009 to 2.3 mb/d in 2020 and to 4.4 mb/d in 2035 in the New Policies Scenario. ** Includes international marine and aviation fuel.

The prices needed to balance oil demand — which varies with the degree of policy effort to curb demand growth — with supply differ markedly across the three scenarios. In the New Policies Scenario, the average IEA crude oil import price reaches $105/barrel in real terms in 2025 on average and $113/barrel in 2035. In the Current Policies Scenario, in which no change in government policies is assumed, substantially higher prices are needed to bring demand into balance with supply. Prices rise more briskly, especially after 2020. The crude oil price reaches $120 per barrel in 2025 and $135/barrel ten years later. Our analysis suggests that the rate of increase in production capacity is relatively insensitive to price, as net capacity additions are constrained by the steep decline in output from existing fields, particularly in non-OPEC countries, problems of access to undeveloped resources and logistical constraints (see the supply section below). Similarly, the increasing dominance of transport in overall oil demand will tend to lower the sensitivity of demand to price, as the alternatives to conventional oil-based fuels struggle to compete in that sector (see the section on sectoral trends below). Prices in the 450 Scenario are considerably lower, levelling off at $90 after 2020, as demand increases much less, peaking by around 2015. The oil demand and supply peak in this scenario is, thus, driven entirely by policy rather than by any geological constraint. The message from this analysis is clear: the weaker and slower the response to the climate challenge, the greater the risk to oil-importing countries of oil scarcity and higher prices. Economic activity is expected to remain the principal driver of oil demand in all regions in every scenario, but the relationship weakens in the New Policies Scenario and, to an even greater extent, in the 450 Scenario. On average, since 1980, each 1% increase in gross domestic product (GDP) has been accompanied by a 0.3% rise in primary oil demand (Figure 3.2). This ratio — the oil intensity of GDP, or the amount of oil needed to produce one dollar of GDP — has fallen progressively since the 1970s, though in an Chapter 3 - Oil market outlook

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uneven fashion.2 Oil intensity fell more sharply after 2004, mainly as a result of higher oil prices, which have encouraged conservation, switching to other fuels and spending on more efficient equipment and vehicles. In 2009, global oil intensity (expressed in purchasing power parities, or PPP) was only about half the level of the early 1970s. This downward trend continues in the New Policies Scenario, with intensity falling to onehalf of its 2009 level by 2035, boosted by policies to promote more efficient oil use in end-use sectors and switching to lower carbon fuels, including vehicle fuel-efficiency standards and the phase-out of subsidies (see Part E). Figure 3.2 z Annual change* in global real GDP and primary oil demand in the New Policies Scenario 3.5%

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Regional trends The outlook for oil demand differs markedly across regions. All of the increase in world oil demand between 2009 and 2035 comes from non-OECD countries in every scenario, as OECD demand drops. In the New Policies Scenario, OECD demand falls by over 6 mb/d between 2009 and 2035, but this is offset by an almost 19-mb/d increase in the non-OECD (international bunker demand also rises by almost 3 mb/d). Demand drops in all three OECD regions: progressive improvements in vehicle fuel efficiency, spurred by higher fuel costs as international prices increase as well as government fuel-economy mandates, more than offset the effect of rising incomes (Table 3.2). By contrast, in non-OECD regions, strong economic and population growth, coupled with the enormous latent demand for mobility, more than outweighs efficiency gains in transport.

The biggest increase in demand in absolute terms occurs in China, where it jumps from just over 8 mb/d in 2009 to more than 15 mb/d in 2035 — an increase of 2.4% per year on average in the New Policies Scenario. China accounts for 57% of the global increase 2. Oil prices also affect GDP, by altering energy costs. The rapid run-up in oil prices in the period 2003 to mid-2008 undoubtedly played a role, albeit a secondary one, in provoking the financial and economic crisis of 2008-2009. It follows that a sharp rise in oil prices in the years to come would threaten the global economic recovery.

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in demand. Demand could grow even more if the rising international prices of oil assumed in this scenario were offset by an appreciation of the yuan against the dollar. High as it is, the projected growth rate in the New Policies Scenario is still significantly lower than in the past: Chinese oil use more than quadrupled between 1980 and 2009. Other emerging Asian economies, notably India, and the Middle East also see rapid rates of growth. The latter region has emerged as a major oil-consuming as well as oil-producing region, on the back of a booming economy (helped by high oil prices) and heavily subsidised prices in domestic markets. Middle East countries account for one-fifth of the growth in oil demand over the projection period. Demand in all three OECD regions, by contrast, falls, most heavily in relative terms in the Pacific region and Europe. As a result of these trends, the non-OECD countries’ share of global oil demand (excluding international marine bunkers) rises from 46% in 2009 to 61% in 2035.

*Excludes biofuels demand, which is projected to rise from 1.1 mb/d (in energy-equivalent volumes of gasoline and diesel) in 2009 to 2.3 mb/d in 2020 and to 4.4 mb/d in 2035. **Compound average annual growth rate. ***Includes international marine and aviation fuel.

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Sectoral trends The transport sector is expected to continue to drive the growth in global oil demand. In the New Policies Scenario, transport accounts for almost all of the increase in oil demand between 2009 and 2035, with oil use in power generation falling and consumption in other sectors in aggregate expanding only modestly (Figure 3.3). Transport’s share in global primary oil consumption (including bunker fuels) rises from 53% in 2009 to 60% in 2035. China alone accounts for half of the global increase in oil use for transport. Oil remains the dominant source of energy for transportation, by road, rail, air and sea, though it comes under increasing competition from alternative fuels, notably biofuels and electricity for cars and trains, and natural gas for buses and trucks. The share of oil-based fuels (primarily gasoline and diesel) in total road transportation energy use falls from 96% in 2009 to 89% by 2035, mainly due to increased use of conventional biofuels and, increasingly, advanced biofuels (see Chapter 12). Figure 3.3 z Change in primary oil demand by sector and region in the New Policies Scenario, 2009-2035 OECD Transport

Demand for road transport fuels is set to continue to expand rapidly in the emerging economies in line with rising incomes, which boost car ownership and usage as well as freight, and expanded road networks. In contrast to the OECD regions, these factors more than offset the effect of continuing improvements in vehicle fuel efficiency, a modest expansion of biofuels use and the deployment of full-electric vehicles in the longer-term. Trucks and passenger light-duty vehicles (PLDVs) account for most of the increase in transport-related oil use (Figure 3.4). The passenger-car and truck fleet is growing faster in China than anywhere else: preliminary data show that new car sales topped 13.6 million in 2009, overtaking for the first time sales in the United States. The total car fleet in China is now estimated at almost 40 million — more than twice as big as just three years ago. Car and truck sales are growing rapidly in many other non-OECD countries as well, particularly in Asia. 106

The potential for continued brisk expansion of the vehicle fleet in those countries remains large, as vehicle ownership rates are still well below those in the OECD: there are only 30 cars for every thousand people in China, compared with around 700 in the United States and almost 500 in Europe. In the New Policies Scenario, the total stock of passenger light-duty vehicles in non-OECD countries is projected to quadruple over the projection period to about 850 million, overtaking that of OECD countries soon after 2030 (Figure 3.5). The vehicle fleet of China overtakes that of the United States by around 2030.

The rate of growth in car ownership in non-OECD countries in general and in China in particular is a critical uncertainty for the prospects for global oil use. Holding all other factors equal, a 1% per year faster rate of growth in car ownership in China alone (compared with the global average of 1.8% in the New Policies Scenario) would result in around 95 million more cars on the road in 2035 and 0.8 mb/d of additional oil Chapter 3 - Oil market outlook

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demand — an increase of 0.8% in world demand. Were this faster growth rate applied to all non-OECD countries, demand would, in theory, be about 3.6 mb/d, or 4%, higher. To avoid such an increase, oil prices would have to rise much faster than assumed in this scenario, unless there were faster improvements in vehicle efficiency, fewer kilometres driven per vehicle and/or faster penetration of biofuels and alternative fuel and vehicle technologies. Fuel economy — the amount of fuel consumed in driving one kilometre — is another key uncertainty. Rising incomes will tend to encourage people to opt for larger, more energy-intensive vehicles, though this phenomenon is expected to be more than offset by continuing fuel economy improvements in each vehicle category. Conventional internal combustion engine vehicles are expected to continue to become more efficient, the result of higher oil prices as well as policy initiatives to encourage vehicle manufacturers to develop and market more efficient vehicles and motorists to buy them. A number of countries, including the United States and EU members, have adopted regulations to increase the average vehicle fuel efficiency; others such as China or Korea are also discussing standards (these are taken into account in the New Policies Scenario). Other measures include programmes to encourage fuel-efficient driving, such as the EU-funded Ecodrive programme. In addition, hybrid cars and plug-in hybrids, with significantly better fuel efficiency than conventional cars, together with full-electric vehicles that consume no oil at all directly, account for a growing share of light-duty vehicle sales. In the New Policies Scenario, these new vehicle technologies collectively account for 6% of new passenger vehicle sales by 2020 and 19% by 2035, the bulk of which are hybrids (Figure 3.6).

The combination of more efficient conventional vehicles and the growing contribution of new vehicle technologies results in a drop in the average fuel consumption of new light-duty vehicles sold worldwide from 9.7 litres/100 kilometres (km) of fuel in 2009 to 7.6 litres/100 km in 2020 and 6.7 litres/100 km in 2035 (Figure 3.7). The improvement in fuel economy is greatest in the period to 2015, mainly as a result of stringent new government measures that are assumed to be introduced and the relatively rapid 108

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increase in oil prices. In the period to 2020, the improved efficiency of conventional cars is the main driver. Thereafter, hybrid and, to a lesser extent, plug-in hybrid cars play an increasingly important role. A significant part of the potential efficiency gains from conventional cars is exploited within the first half of the projection period. It is possible to reduce the fuel consumption of a conventional internal combustion engine vehicle of medium size on average worldwide by about 40% within the next two decades, compared with the year 2000 (IEA, 2009). Beyond this, the only way that average vehicle fuel efficiency can be further reduced significantly without reducing the size of the vehicle is through the deployment of alternative technologies.

Litres per 100 kilometres

Figure 3.7 z Average fuel economy of new passenger light-duty vehicle sales by region in the New Policies Scenario 13

The net result of the projected trends in vehicle ownership, fuel economy and technology is a rise in per-capita oil use for road transportation in all non-OECD regions and a fall in all three OECD regions in each scenario. Yet average per-capita demand remains much lower in the non-OECD by 2035, mainly because incomes and, therefore, vehicle ownership rates remain significantly lower. In the New Policies Scenario, percapita road-transport-related oil demand is on average four times higher in the OECD than in non-OECD regions by the end of the Outlook period, down from seven times in 2009 (Figure 3.8). Given the limitations on further improving the efficiency of conventional vehicles, how quickly new vehicle technologies penetrate the car market will have a major impact on oil demand for road transport. The pump price of oil-based fuels and advances in alternative vehicle technologies to lower their cost and improve their operational performance are the main factors. For now, alternative technologies are struggling to compete on cost, which is holding back their deployment. However, a relatively modest but sustained rise in the price of oil-based fuels and/or a drop in the cost of these new technologies could make them attractive to end users and lead to rapid growth in their uptake. In the United States, for example, low fuel taxes and, hence, low pump prices mean that conventional hybrids pay back their much higher purchase cost to motorists only after 120 000 km at 2009 fuel prices (Figure 3.9). At an average of 20 000 km per Chapter 3 - Oil market outlook

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year, the payback period is therefore around six years — far too high to persuade most motorists to opt for this type of vehicle. However, a 30% fall in the difference in the cost of buying a hybrid would cut the payback period to four years, increasing significantly the attractiveness of such a car to motorists. Figure 3.8 z Road transportation per-capita oil consumption by region in the New Policies Scenario 2009

Note: Assumes vehicle life of 15 years and average 2009 gasoline price of $0.65 per litre ($2.46 per US gallon). ICE is internal combustion engine.

Pump prices of gasoline and diesel vary enormously across countries, because of differences in tax rates and — in some countries — subsidies (see Part E). There are also differences in the relative prices of hybrids and conventional cars. These factors result in a big variation in the attractiveness to motorists of buying hybrids today. The payback period is currently shortest in Germany and France, where fuel taxes are 110

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highest (Figure 3.10). In China, the payback period is relatively long, at close to eight years (assuming average mileage there of 9 000 km a year). Yet even the quickest paybacks are too long to appeal to most motorists. In practice, there are many other factors that come into play in determining a motorist’s decisions about which car to buy, so that the payback period on a more efficient car typically has to be very short to swing the decision. But higher fuel prices and lower purchase costs would reduce the payback period and greatly increase the appeal of hybrids. For example, an increase in international oil prices of one-third would reduce the payback period of a hybrid in China from about eight to seven years; a 30% drop in the premium for a hybrid car over a conventional car would cut the payback period to slightly less than six years. Achieving cost-competitiveness for other alternative vehicle options, such as plug-in hybrids and electric cars, is likely to require more than just higher oil prices. Despite the current strong momentum towards deployment of these vehicles, a number of issues that raise doubts about their long-term viability remain open. Technical aspects would need to be addressed for global mass manufacturing of electric cars, such as standardisation of batteries and differences in voltage by country, and, even then, it is unclear whether consumers would be prepared for the prospective limitations on driving range and the length of the necessary recharging time. It is not likely that high oil prices alone will suffice to create a global market for electric cars; policy intervention will probably be required too. In light of all these factors, we conservatively project that electric cars and plug-in hybrids account for only 2.6% of car sales by 2035 in the New Policies Scenario. Figure 3.10 z Payback period for hybrid light-duty vehicles in selected countries at current costs 2009

There is also considerable scope for reducing the amount of oil-based fuels used in road freight — a major contributor to the growth of road-transport oil demand in non-OECD countries — through more efficient vehicles and the use of alternative fuels. Medium and heavy freight traffic, is responsible for 30% of all transport oil demand worldwide today and this share is projected to increase to 35% by 2035 (Figure 3.4, above). One Chapter 3 - Oil market outlook

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uncertainty for road-freight oil use is the outlook for compressed natural gas as a fuel, which could displace diesel. The recent fall in gas prices relative to oil prices, especially in North America, has led to greater interest in promoting compressed natural gas (CNG) as a road fuel for fleet vehicles, including lorries, trucks and buses, as a way of reducing costs, improving energy security and reducing emissions of local pollutants and, to a limited degree, greenhouse gases. CNG already makes a significant contribution to meeting road-transport fuel needs in several countries, notably in Pakistan and Argentina, but in most major economies CNG use is marginal. This could change, especially if gas prices remain low relative to oil prices. However, there are major barriers to the expansion of natural gas use, including the cost and practicalities of on-board fuel storage, the cost of installing the infrastructure for delivering and distributing the fuel at existing refuelling stations and the risk that prices might move against gas in the future.3 Nonetheless, the prospects — especially as a fuel for fleet vehicles (as the infrastructure costs are lower) — have certainly improved in recent years. In the New Policies Scenario, CNG use worldwide more than triples between 2009 and 2035, from almost 20 billion cubic metres (bcm) to over 60 bcm. The amount of oil saved as a result increases from about 300 thousand barrels per day (kb/d) to over 1 mb/d. Most of the increase in oil savings comes from non-OECD countries, but North America, where wholesale gas prices are lowest, makes a significant contribution (Figure 3.11). By 2035, around 4% of the heavy-duty vehicle fleet in North America runs on CNG — up from almost nil today. Oil savings could be much greater; if CNG took a 5% share of the global freight vehicle fleet by 2035, compared with 1.5% in the New Policies Scenario, oil consumption would be reduced by a further 0.6 mb/d. Figure 3.11 z Oil savings from use of natural gas in road transport by region in the New Policies Scenario Latin America

Another important factor in the future oil demand increase is the rate of growth of fuel use in the aviation sector. Combined, jet fuel and aviation gasoline demand grew at 3. See, for example, IEA (2010a) and Box 10.1 in IEA (2009).

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a similar pace as total oil demand in transport between 1980 and 2009, a steady 2.1% per year, making up 12% of all transport oil demand in 2009. This share is projected to increase over the projection period to 14% by 2035 in the New Policies Scenario, mainly driven by non-OECD countries. The largest single contributor to growth in aviation oil demand is China, where demand is projected to expand by 2.6% per year (Figure 3.12). In the OECD, the aviation sector is the only major sector that sees any significant growth in oil demand. Government measures aimed at curbing aviation-fuel demand have been limited to date, in sharp contrast to the action taken in the road-transport sector. The inclusion of aviation to the EU Emission Trading Scheme from 2012 is one of the few policy actions undertaken. However, the industry itself has made significant efforts to reduce fuel use, through operational changes and investments in more efficient aircraft.

There is little prospect of any significant long-term increase in oil demand in nontransport uses, as oil is expected to lose market share to coal, gas and other fuels. Globally, the use of oil in other sectors in aggregate remains flat over the projection period in the New Policies Scenario, at around 39 mb/d; an increase in non-OECD countries (mainly in the industry, residential and services sectors, and as a feedstock in the petrochemical industry) is more than outweighed by a drop in OECD demand (reflecting energy efficiency gains and some switching to gas in buildings). Oil use in power generation falls in every region bar the Middle East.

Resources and reserves According to the Oil and Gas Journal ( O&GJ, 2009), proven reserves of oil worldwide at the end of 2009 amounted to 1 354 billion barrels — a marginally higher volume than estimated a year earlier and the highest level ever attained (see Box 3.1 for definitions). Reserves have more than doubled since 1980 and have increased by onethird over the last decade. Half of the increase since 2000 is due to Canadian oil sands reserves; most of the remainder is due to revisions in OPEC countries, particularly in Chapter 3 - Oil market outlook

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Iran, Venezuela and Qatar. There are continuing question-marks over the estimates for some OPEC countries and their comparability with the figures for other countries.4 Notwithstanding these uncertainties, OPEC countries account for about 70% of the world total reserves, with Saudi Arabia holding the largest volume (Figure 3.13). Figure 3.13 z Proven oil reserves in the top 15 countries, end-2009 0

Box 3.1 z Defining and measuring oil and gas reserves and resources In the WEO, we use the following definitions, drawing on the Petroleum Resources Management System (SPE, 2007) and US Geological Survey (USGS, 2000): z A proven reserve (or 1P reserve) is the volume of oil or gas that has been

discovered and for which there is a 90% probability that it can be extracted profitably on the basis of prevailing assumptions about cost, geology, technology, marketability and future prices. z A proven and probable reserve (or 2P reserve) includes additional volumes

that are thought to exist in accumulations that have been discovered and have a 50% probability that they can be produced profitably. z Reserves growth refers to the typical increases in 2P reserves that occur as oil

or gas fields that have already been discovered are developed and produced.

cumulative production to date. z Oil originally in place refers to the total amount of oil or gas contained in a

reservoir before production begins. z The recovery factor is the share of the oil or gas originally in place that

is ultimately recoverable (i.e. ultimately recoverable resources/original hydrocarbons in place). Definitions of reserves and resources, and the methodologies for estimating them, vary considerably around the world, leading to confusion and inconsistencies. In addition, there is often a lack of transparency in the way reserves are reported: many national oil companies in both OPEC and non-OPEC countries do not use external auditors of reserves and do not publish detailed results. OPEC figures of proven reserves may be more comparable to figures of proven and probable reserves in other parts of the world. The IEA continues to work with the UN Economic Commission for Europe, the Society of Petroleum Engineers and other organisations on harmonising the way reserves and resources are defined and estimated in order to provide a clearer picture of how much oil and gas remains to be produced. In 2009, the US Securities and Exchange Commission (SEC) introduced updated guidelines for evaluating oil and gas reserves to take account of recent technological and market developments. US-quoted companies are now able to use seismic and numerical modelling techniques and data from down-hole tools in estimating reserves. They can now use an average 12-month price to value reserves, rather than the year-end price, and can provide sensitivity analyses of reserves estimates, using different price outlooks. The SEC also now permits companies to report probable and possible reserves, as well as proven reserves. Producers can now also report reserves of unconventional oil. The aim of these changes is to provide a better insight into the reporting companies’ long-term production potential.

The bulk of proven reserves, which include all types of oil (Box 3.2), are conventional: the only significant volumes of unconventional oil included in the figure from O&GJ for end-2009 are an official estimate of 170 billion barrels for Canadian oil sands reserves, of which some 16% are currently “under active development”. Globally, conventional and unconventional reserves combined are equal to about 46 years of current production. The reserves to production ratio5 has increased in the last two years as a result of the recession-induced drop in demand for oil and continuing modest increases in reserves. 5. R/P ratios are commonly used in the oil and gas industry as indicators of production potential, but do not imply continuous output for a certain number of years, nor that oil production will stop at the end of the period. They can fluctuate over time as new discoveries are made, reserves at existing fields are reappraised, and technology and production rates change.

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Box 3.2 z Definitions of different types of oil in the WEO For the purposes of this chapter (and Chapter 4), the following definitions are used: z Oil comprises crude, natural gas liquids, condensates and unconventional oil, but does not include biofuels (for the sake of completeness and to facilitate comparisons, relevant biofuels quantities are separately mentioned in some sections and tables). z Crude makes up the bulk of oil produced today; it is a mixture of hydrocarbons

that exist in liquid phase under normal surface conditions. It includes condensates that are mixed-in with commercial crude oil streams. z Natural gas liquids (NGLs) are light hydrocarbons that are contained in

associated or non-associated natural gas in a hydrocarbon reservoir and are produced within a gas stream. They comprise ethane, propane, butane, isobutene, pentane-plus and condensates.6 z Condensates are light liquid hydrocarbons recovered from associated or non-

associated gas reservoirs. They are composed mainly of pentane (C5) and higher carbon number hydrocarbons. They normally have an API gravity of between 50° and 85°. z Conventional oil includes crude and NGLs. z Unconventional oil includes extra-heavy oil, natural bitumen (oil sands),

(see Chapter 12). Almost half of the increase in proven reserves in recent years has come from revisions to estimates of reserves in fields already in production, rather than new discoveries. Although discoveries have picked up in recent years with increased exploration activity (prompted by higher oil prices), they continue to lag production by a considerable margin: in 2000-2009, discoveries replaced only one out of every two barrels produced — slightly less than in the 1990s (even though the amount of oil found increased marginally) — the reverse of what happened in the 1960s and 1970s, when discoveries far exceeded production (Figure 3.14). The contribution of offshore discoveries, including deepwater, has increased significantly since the early 1990s. Since 2000, more than half of all the oil that has been discovered is in deep water. Although some giant fields have been found, the average size of fields being discovered has continued to fall. The New Policies Scenario requires average annual development of 9 billion barrels of new discoveries from 2015 onwards (see the section on oil production prospects below).

6. See IEA (2010c) for a detailed analysis of the medium-term prospects for NGLs.

The volume of ultimately recoverable resources, comprising proven and probable reserves, plus oil that is yet to be discovered and additional volumes of oil in existing fields that could be “proven up” in the future, is estimated to be much bigger than proven reserves. Yet there is uncertainty about this figure and, therefore, about just how much oil remains to be produced. The main uncertainties lie in estimating how much oil was originally in place in the world and in evaluating how much of this resource can be recovered profitably (the recovery factor). The latter is heavily influenced by future trends in oil prices and oilfield development costs, which will hinge on assumptions about technology and the underlying cost of various inputs to oil production, as well as geological considerations. The leading source of estimates of ultimately recoverable resources of conventional crude oil and NGLs is the US Geological Survey (USGS). It last carried out a major assessment of global resources in 2000, but has carried out partial updates covering specific basins since then, including a major reassessment of the Arctic region in 2008 (USGS, 2008). Based on those assessments, we estimate that around 2.5 trillion barrels of conventional oil remain to be produced worldwide as of the beginning of 2010, taking account of cumulative production to date and mean estimates of ultimately recoverable resources. Of this total, 900 billion barrels are in deposits that are yet to be found. At the start of 2010, the proportion of remaining recoverable resources classified as proven reserves varied widely across regions: proven reserves accounted for 68% of remaining recoverable resources in the Middle East, but only 17% in North America. As with reserves, the bulk of the remaining resources are in the Middle East and the former Soviet Union countries (Figure 3.15). In the New Policies Scenario, around half of the conventional resources are produced by 2035, but the share reaches 61% for non-OPEC countries as a group compared with only 47% for OPEC. By end-2009, only 32% of global ultimately recoverable resources had been produced. However, these estimates do not include unconventional resources — oil sands, extra-heavy oil and oil shales. The size of these resources is uncertain, as they have been studied much less than conventional resources, but they are certainly very large; potentially around 2 to 3 trillion barrels of unconventional oil may be economically recoverable. Chapter 3 - Oil market outlook

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Figure 3.15 z Proven reserves, recoverable resources and production of conventional oil by region in the New Policies Scenario 0

Oil supply follows the same trajectory as demand in each of the three scenarios, though production of oil (crude, NGLs and unconventional oil) rises marginally less than overall supply, due to increasing processing gains.7 In the New Policies Scenario, total oil production reaches 96 mb/d by 2035 (Table 3.3). In the Current Policies Scenario, production continues to expand through to 2035, though the pace slows over the second half of the projection period. In the 450 Scenario, production peaks before 2020 and then declines steadily to 2035. The breakdown of production between OPEC and non-OPEC, and between conventional and unconventional oil differs across the three scenarios. The share of OPEC in overall production by the end of the projection period is highest in the 450 Scenario, at more than 53%, as lower oil prices inhibit investment 7. Oil refining involves the upgrading of heavy oil into lighter products, which reduces their density and gives rise to an increase in volume for a given amount of energy content. Processing gains as a share of overall supply increase slightly in all three scenarios as a result of more upgrading of oil feedstocks in response to the shift in demand towards lighter products such as diesel and gasoline.

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in high-cost resources, mainly in non-OPEC countries. The share of unconventional oil is highest in the Current Policies Scenario, as higher oil prices stimulate more investment in developing those higher-cost resources.

3

Table 3.3 z Oil production and supply by source and scenario (mb/d) New Policies Scenario

There is also a marked difference in the profile of crude oil production across the three scenarios, with global output rising in the Current Policies Scenario to 74 mb/d by 2035, but reaching a plateau by 2020 in the New Policies Scenario (Figure 3.16). The increase in production in the former scenario comes with the higher prices that are needed to bring forth more investment in productive capacity. Slower global demand growth and lower prices in the New Policies Scenario mean that crude oil resources can be developed in a steadier fashion, keeping crude oil production in that scenario at a plateau of around 68-69 mb/d from 2015 (marginally below the all-time peak of about 70 mb/d reached in 2006). In the 450 Scenario, the strong greenhouse-gas emissionsreduction policies assumed quickly send oil demand growth into reverse, causing prices to level off, resulting in less investment in conventional oilfields, a marginal drop in oil output to 2020 and accelerating decline thereafter (see Chapter 15). Overall, worldwide production of both NGLs and unconventional oil increases much more than crude oil between 2009 and 2035 (Figure 3.17). The increase in output of all three types of oil is highest, unsurprisingly, in the Current Policies Scenario and lowest in the 450 Scenario. Conversely, the increase in production of biofuels (not included in our definition of oil — see Box 3.3) is highest in the 450 Scenario, adding more to liquids supply than any of the other sources. Chapter 3 - Oil market outlook

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mb/d

Figure 3.16 z World crude oil production by scenario 75

Current Policies Scenario

70

New Policies Scenario

65

450 Scenario

60 55 50 1990

1995

2000

2005

2010

2015

2020

2025

2030

2035

Figure 3.17 z Change in world oil and biofuels production by scenario, 2009-2035 Crude oil Current Policies Scenario

In the New Policies Scenario, non-OPEC production in total peaks before 2015 at around 48 mb/d and then begins to decline, falling to 46 mb/d by the end of the projection period (Figure 3.18). Conventional oil production goes into decline before 2015 but, until around 2025, this decline is offset by rising unconventional production — chiefly oil sands in Canada, supplemented by about 500 kb/d of oil from coal-to-liquids (in China, South Africa and the United States), gas-to-liquids and oil shales. OPEC oil production, by contrast, continues to grow throughout the projection period, on the assumption that the requisite investment is forthcoming. OPEC share of world production rises from 41% in 2009 to 52% in 2035. The shares of NGLs and unconventional oil in world production also grow markedly over the projection period. 120

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Box 3.3 z Enhancements to the oil-supply model for WEO-2010 The IEA oil supply model has been improved for this year’s Outlook, to allow for more complex modelling of global supply scenarios, with more detailed assumptions per country and resource category. This modelling includes simulating the impact of different assumptions about resource endowment and accessibility, oil prices, costs (finding and development and lifting), fiscal terms and investment risks, logistical constraints on the pace of resource exploration and development, production profiles and decline rates, carbon emission regulations and CO2 prices, and technological developments. The model projects supply, investment in exploration and production, and company and government revenues by country/region and by resource category. The projections are underpinned by current field production profiles and decline rates, drawing on the detailed results of the field-by-field analysis of WEO-2008 (IEA, 2008), and take into account specific near-term project development plans (IEA, 2010b). OPEC production projections take into account stated policies on resource depletion and investment.

mb/d

Figure 3.18 z World oil production by source in the New Policies Scenario 100

Although global oil production in the New Policies Scenario increases by only 15 mb/d between 2009 and 2035, the need for new capacity is much larger because of the need to compensate for the decline in production at existing fields as they pass their peak and flow-rates begin to drop. Crude oil output from those fields that were in production in 2009 drops from 68 mb/d in 2009 to 16 mb/d by 2035, a fall of three-quarters (Figure 3.19). This projection takes account of the build-up and decline rates of different types of fields in each region, drawing on the detailed field-by-field analysis carried out in 2008 (IEA, 2008). On average, the production-weighted rate of decline in production year-on-year accelerates through the projection period, as more and more fields pass their peak and enter their decline phase and as the share of smaller and offshore fields, with higher decline rates, grows. By 2035, aggregate output from fields already in Chapter 3 - Oil market outlook

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production in 2009 is declining at a rate of 8.3% per year.8 We calculate that, over the Outlook period, there is a need to add a total of 67 mb/d of gross capacity in order to compensate for the decline at existing conventional oilfields and to meet the growth in demand. The gross new capacity required by 2020 is 28 mb/d. Just under 60% of the crude oil produced from new fields in 2035 is from fields that have already been found, most of which are in OPEC countries. The bulk of the oil that is produced in 2035 from new fields that are yet to be found is in non-OPEC countries, largely in deep water.

mb/d

Figure 3.19 z World oil production by type in the New Policies Scenario 100

As noted above, slightly more than half of the world’s ultimately recoverable resources of conventional oil are produced by the end of the projection period in the New Policies Scenario (see Figure 3.15, above). Cumulative production reaches 1.9 trillion barrels by the end of 2035, up from 1.1 trillion barrels at end-2009. The share of unconventional oil resources that are produced by 2035 is much lower, at less than 3% (based on a conservative estimate of 1.9 trillion barrels). The size of ultimately recoverable resources of both conventional and unconventional oil is obviously crucial in determining how soon global oil production peaks and at what level. However, the estimate of their size inevitably changes over time, as advances in technology open up new sources or areas of production and lower their cost of development, shifting more of the oil originally in place worldwide into the category of recoverable resources (see the Spotlight). Higher prices — as we assume in all three scenarios in this Outlook — would also effectively increase the recovery factor. Non-OPEC production is particularly sensitive to the estimated size of conventional resources, as there are fewer constraints on the development of those resources. In order to test the sensitivity of the level of production in non-OPEC countries to the level of ultimately recoverable resources, we have modelled the impact of both higher and lower levels of conventional oil resources, based broadly on the upper and lower bounds estimated by the USGS (corresponding to 5% and 95% probability) and restrictions on resource access, particularly for volumes in environmentally sensitive areas, deep water and the Arctic (Figure 3.20). In the New Policies Scenario, the lower 8. This takes account of enhanced oil recovery projects that are implemented at currently producing fields.

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resource case would lead to a much faster decline in non-OPEC production compared with the mean case, with production falling a further 6 mb/d by 2035. Assuming unchanged supplies of NGLs and unconventional oil, this would increase the call on OPEC oil by the same amount. In reality, it is far from certain that OPEC would be willing or able to produce this much oil within this timeframe. Were OPEC producers unwilling or unable to make up the difference, oil prices would rise, stimulating more investment in unconventional non-OPEC supplies and choking off demand.

Offshore fields are expected to account for a slightly growing share of crude oil production, especially during the first half of the projection period, when a number of new deepwater projects are brought online in non-OPEC countries (Figure 3.21). In the long term, the offshore share levels off, as large new increments to onshore production in the Middle East play an increasingly important role. In aggregate, worldwide crude oil production from offshore fields rises marginally, from 21.6 mb/d in 2009 to a peak of 23 mb/d by 2025, falling back slightly by 2035 in the New Policies Scenario. Their share in world crude oil production rises from 32% in 2009 to 34% in 2025 and then drops back to 33% in 2035. The contribution from deepwater fields (at depths of more than 400 metres) rises from around 5 mb/d in 2009 to nearly 9 mb/d in 2035. In non-OPEC countries, the share of offshore fields in total crude oil production rises from just over one-third to almost half. NGLs account for almost half of the increase in overall global oil production between 2009 and 2035 in the New Policies Scenario, their output rising from 10.8 mb/d to nearly 18 mb/d (Table 3.4). Production increases particularly sharply in the near term, jumping by more than one-quarter already by 2015, as a result of a number of major gas projects coming on stream. The strong rise in natural gas production, particularly in the Middle East, where gas generally has higher liquids content than in most other regions, is the main driver, but other factors, including reduced flaring, which will make available more associated gas (which tends to be relatively wet), and the increasing wetness of gas reservoirs now being developed in other areas helps boost NGLs supplies. These factors more than offset the projected increase in the share of non-associated gas in total production (Figure 3.22). Chapter 3 - Oil market outlook

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mb/d

Figure 3.21 z World crude oil production by physiographical location in the New Policies Scenario 80

Deepwater: OPEC

70

Deepwater: non-OPEC

60

Shallow water: OPEC

50

Shallow water: non-OPEC Onshore: OPEC

40

Onshore: non-OPEC

30 20 10 0

2005

2009

2015

2020

2025

2030

2035

Table 3.4 z Natural gas liquids production by region in the New Policies Scenario (mb/d)

Peak oil revisited: is the beginning of the end of the oil era in sight? Public debate about the future of oil tends to focus on when conventional crude oil production is likely to peak and how quickly it will decline as resource depletion passes a certain point. Those who argue that an oil peak is imminent base their arguments largely on the indisputable fact that the resource base is finite. It is held that once we have depleted half of all the oil that can ever be recovered, technically and economically, production will enter a period of long-term decline. What is often missing from the debate is the other side of the story — demand — and the key variable in the middle — price. How much capacity is available to produce oil at any given moment depends on past investment. Decisions by oil companies on how much and where to invest are influenced by a host of factors, but one of the most important is price (at least relative to cost). And price is ultimately the result of the balance between demand and supply (setting aside short-term fluctuations that may have as much to do with financial markets than with oil-market fundamentals). In short, if demand rises relative to supply capacity, prices typically rise, bringing forth more investment and an expansion of capacity, albeit usually with a lag of several years.

Another misconception is that the amount of recoverable oil is fixed. The amount of oil that was ever in the ground — oil originally in place, to use the industry term — certainly is a fixed quantity, but we have only a fairly vague notion of just how big that number is. But, critically, how much of that volume will eventually prove to be recoverable is also uncertain, as it depends on technology, which will certainly improve, and price, which is likely to rise: the higher the price, the more oil can be recovered profitably. An increase of just 1% in the average recovery factor at existing fields would add more than 80 billion barrels to recoverable resources (IEA, 2008). So, the chances are that the volume of resources that prove to be recoverable will be bigger than the mean estimate we use to project production, especially since that estimate does not include all areas of the world. Even if conventional crude oil production does peak in the near future, resources of NGLs and unconventional oil are, in principle, large enough to keep total oil production rising for several decades. Clearly, global oil production will peak one day. But that peak will be determined by factors on both the demand and supply sides. We project a peak before 2020 in the 450 Scenario. In the New Policies Scenario, production in total does not peak before 2035, though it comes close to doing so, conventional crude oil production in that scenario holding steady at 68-69 mb/d over the entire projection period and never attaining its all-time peak of 70 mb/d in 2006. In other words, if governments put in place the energy and

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climate policies to which they have committed themselves, as we assume in this scenario, then our analysis suggests that crude oil production has probably already peaked. If governments act vigorously now to encourage more efficient use of oil and the development of alternatives, then demand for oil might begin to ease quite soon and we might see a fairly early peak in oil production. That peak would not be caused by any resource constraint. But if governments do nothing or little more than at present, then demand will continue to increase, the economic burden of oil use will grow, vulnerability to supply disruptions will increase and the global environment will suffer serious damage. The peak in oil production will come then not as an invited guest, but as the spectre at the feast. The strong growth in NGLs supply will lighten the overall product mix, although this effect is expected to be at least partially offset by a rise in the share of extra-heavy oil and natural bitumen in overall oil production (Figure 3.23). This changing production mix will require more investment in upgraders for the heavier crudes and bitumen, and condensate and NGL processing facilities for the lighter fluids. Much of the increase in the supply of NGLs is likely to be used a petrochemical feedstock, notably in the Middle East. Figure 3.23 z World oil production by quality in the New Policies Scenario 100% 80% 60%

Sources: Data provided to the IEA by the Italian oil company, Eni; IEA estimates and analysis.

The structure of the global oil industry is set to change strikingly in the coming decades, as production shifts to countries dominated by national oil companies, which control most of the world’s remaining oil resources. In the New Policies Scenario, national companies as a group are projected to contribute all of the growth in global oil production over the projection period, their share rising from 58% in 2009 to about 66% in 2035, based on their current resource ownership (Figure 3.24). These projections assume sufficient investment 126

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is made in exploration, development and production to meet demand at the assumed price. The major resource-rich countries may favour slower depletion of their hydrocarbon resources. In some cases, there are also doubts about the financial and technical ability of national companies to bring new capacity on stream in a timely manner.

3

mb/d

Figure 3.24 z World oil production by type of company in the New Policies Scenario 100

North America will remain an important non-OPEC producing region, with output projected to rise over the next quarter of a century in the New Policies Scenario (Table 3.5). In Canada, conventional oil production declines steadily, but this is more than offset by rapid growth in output from oil sands (see Chapter 4). As new policies to mitigate climate change take hold, the increasing amount of carbon dioxide (CO2) captured during oil-sands production is accompanied by growth in CO2 enhanced oil recovery projects in the ageing conventional fields of Alberta, slowing their production declines. In the eastern seaboard and Arctic regions, production holds steady, with slow declines in established projects such as Hibernia, Terra Nova and White Rose being offset by new projects. Arctic developments are expected to be slow and provide only small volumes, due to the relatively modest resource endowment, high costs and tighter environmental regulations in the aftermath of the Macondo disaster offshore of the US Gulf Coast. With the short drilling season and strict requirements for sameseason relief-well drilling in case of an accident, costs may well increase in the first half of the projection period, outstripping the impact of technological advances. Oil production in the United States is projected to continue to fall slowly in the medium term, but then recovers towards the end of the projection period as higher oil prices spur growth in enhanced recovery and unconventional oil. In recent years, increased production offshore in the Gulf of Mexico has helped offset the continuing decline in older producing areas. But with the rapid decline rates characteristic of deep offshore projects with large upfront capital expenditures, new offshore regions will need to be opened to drilling to limit the overall decline in production. In the aftermath of the Macondo disaster, such opening of new areas to drilling, which was part of proposed legislation, is Chapter 3 - Oil market outlook

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likely to proceed only slowly, if at all (Box 3.4). Production of NGLs in the United States is projected to remain high, as indigenous production of gas increases gradually, driven by the shale-gas revolution. Additional volumes of unconventional oil, mainly from coal-toliquids plants, supplement supply, especially towards the end of the projection period. Mexico continues to struggle to bring new fields on-line to offset the rapid decline of the Cantarell super-giant field. Production from Cantarell dropped from its peak of 2.2 mb/d in 2003 to an estimated 0.5 mb/d by the middle of 2010. This precipitous decline is linked to the way production has been augmented using nitrogen injection and the highly fractured geology of the field, where most of the producible oil was contained in natural fractures and so was produced quickly. Pemex, the national oil company, has implemented various tertiary recovery technologies and now expects the rate of decline to moderate. Production from new fields has not been able to keep pace with Cantarell’s decline, with production from new projects such as Chicontepec rising much more slowly than expected. Nonetheless, significant resources are thought to be present offshore in the Mexican waters of the Gulf of Mexico, so after a continued decline in the first part of the Outlook period, overall Mexican oil production is expected to inch back up as new projects come on stream. With rising domestic demand, Mexico’s role as an exporter to the United States is set to continue to diminish. Table 3.5 z Non-OPEC oil production in the New Policies Scenario (mb/d)

Production in Europe, mainly in the North Sea, continues its steady decline from 4.5 mb/d in 2009 to 2.1 mb/d in 2035. Recovery rates are likely to continue to rise as tertiary recovery technologies are deployed, partially offsetting the impact of dwindling new discoveries. Elsewhere in the OECD, production in the Pacific, already only 0.7 mb/d, continues to decline, the fall in crude oil production more than offsetting rising output of NGLs and CTL in Australia (see Chapter 4). Box 3.4 z Impact of the Gulf of Mexico oil spill The tragic accident that occurred at the end of April at the Macondo well in the Gulf of Mexico will have both short-term and long-lasting consequences for the oil industry. Although not all the facts are known at the time of writing, it appears that a series of human errors and equipment failures led to an uncontrolled blow-out while the well was being completed. The resulting explosion killed 11 people and sank the drilling rig, provoking a major oil spill. Over 4 million barrels of oil are reported to have been released into the Gulf of Mexico during the four months that it took to cap the well.

The accident has led to a de facto moratorium on drilling in the Gulf of Mexico with floating rigs; the US Administration announced a six-month moratorium in May, but this decision was initially over-ruled and is now being reviewed in court. In any event, deepwater drilling activity there has more or less come to a halt. Drilling is expected to resume only after an extensive review of regulations and contingency procedures. One plausible scenario is for drilling in moderate water depths to resume gradually over the next few months, while deeper water operations may not resume until new technologies to mitigate the consequences of such an accident are put in place. The medium-term effect on production will obviously depend on the duration of the moratorium: we estimate that the drop in production (in the Gulf of Mexico) would be of the order of 100 to 200 kb/d per year of stopped activity. In the longer term, tighter regulations on deepwater drilling are likely to curb the growth of production in other parts of the United States — particularly those areas that have not yet been opened to drilling. A full moratorium is unlikely to be declared in other regions with deepwater production, notably Brazil, West Africa, the North Sea and Canada. However, they have already started reviewing their regulations and will continue to do so when all the facts from the Macondo accident are known. Corporate policies on deepwater operations are also undergoing changes, reflecting potentially increased liabilities in the event of an accident; it is likely that some smaller companies will withdraw from deepwater activities. Overall, new regulations are likely to result in some delays to deepwater projects all over the world. This is taken into account in our modelling of oil production in this Outlook. But the capital planned to be spent by oil companies for deepwater projects would probably be at least partly re-allocated to other locations, bringing production from other projects forward, so the net impact on global oil supply is expected to be small.

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In principle, tighter regulatory requirements would lead to higher costs for developing deepwater resources. However, the main cost driver will remain drilling rig day-rates, themselves driven by the utilisation rates of available rigs. A moderate slowdown in deepwater developments could constrain any cost increases. Coupled with improvements in technology prompted by the lessons learned from the accident, deepwater developments are likely to continue to play a key role in the world supply/demand balance at the oil price trajectories projected in the three scenarios. Russia has consolidated its position as the world’s leading oil producing country with increases in production in 2009 and 2010, driven by a more favourable tax regime, particularly for new fields in eastern Siberia. Although resources are thought to be plentiful in the vast, remote regions of eastern Siberia, high development costs will probably mean that the region is developed only slowly. Allowing for a possible tightening of the fiscal regime, at least in the early part of the projection period, as the Russian government needs to replenish its coffers after the economic downturn of the last two years, Russian oil production is projected to remain relatively flat to 2015, with new projects slowly coming online to offset decline in the mainstay producing region of western Siberia. However, in the longer term, oil production falls steadily, to slightly over 9 mb/d by 2035, despite a projected increase in NGLs production as natural gas output expands (from around 580 bcm in 2009 to over 800 bcm by 2035). Oil production in the leading Caspian oil-producing country, Kazakhstan, is projected to increase throughout the projection period, before decline sets in at the major new offshore fields and production stabilises at nearly 4 mb/d (see Chapter 17). Oil production in Azerbaijan, the only other significant producer in the region, levels out at 1.3 mb/d in the next few years and then starts to decline as 2020 approaches, reaching 0.9 mb/d by 2035. Exports from both countries will depend on policies to improve energy efficiency, in order to rein-in the growth of demand with growing prosperity.

China is projected to maintain production close to the current level of 3.8 mb/d to 2015, followed by a steady decline as resource depletion sets in. A similar situation holds for other non-OPEC Asian countries, with production in the region as a whole dropping from 7.4 mb/d in 2009 to 5 mb/d by 2035. Africa still has substantial scope to increase oil production, but with the slow pace of development in recent years and political instability in some countries, a steady decline in non-OPEC production is projected over the Outlook period. The deepwater offshore West Africa region is in the early phases of its development, and production there is expected to steadily increase in spite of the rapid decline rates characteristic of projects in such areas. New producing countries, such as Ghana or Uganda, are projected to make a growing but modest contribution to the oil production of the region. Oil development in Sudan has been halted by political risks, but the country has the potential to increase production in the longer term. 130

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Latin America sees the second-fastest rate of increase in oil production of any non-OPEC region in the New Policies Scenario. Output growth is led by Brazil, where, thanks to several major deep water offshore discoveries in the last few years in pre-salt layers (so called because the hydrocarbon reservoirs are located underneath thick salt deposits and were therefore difficult to spot on 3D seismic data before recent advances in that technology), including the Tupi and Jupiter fields, production increases to 5 mb/d by 2025 and then levels off through to the end of the projection period. The Tupi field, a probable super-giant found in 2006, with recoverable resources estimated to be as much as 8 billion barrels, is due to enter production in 2011. Total production from the presalt projects (including Tupi) is projected to reach about 1.4 mb/d by 2020. Discoveries of other big fields in the pre-salt layer would allow for higher peak production and extend the plateau for a longer period. The pre-salt area is thought to contain as much as 30 billion barrels of recoverable resources — twice the current proven reserves of Brazil. The deposits are also gas rich, so NGLs production is also set to increase. OPEC production outlook in the New Policies Scenario OPEC accounts for all of the projected growth in global oil production between 2009 and 2035 in the New Policies Scenario (see Table 3.3 above).9 Roughly 16% of the increase in OPEC output goes to meet the growth in local consumption. The growth in OPEC output is expected to come from four main sources (Table 3.7).  Further expansion of Saudi crude oil production and increased NGLs supply as the

country’s gas production expands substantially.  The re-emergence of Iraq as one of the world’s leading oil-producing countries

(Box 3.5), commensurate with its large resource base.  A large increase in NGLs production, linked to increased gas production, especially in

OPEC Middle East countries (where most of the increased gas supply goes to meeting booming domestic demand), and increasing exports from Qatar and Algeria.  The emergence of unconventional oil production from the Orinoco belt in Venezuela

and from gas-to-liquids plants, notably in Qatar and Nigeria (see Chapter 4).

Saudi Arabia is projected to regain from Russia its place as the world’s biggest oil producer, its combined output of crude oil and NGLs rising from 9.6 mb/d in 2009 to 11.5 mb/d in 2020 and 14.6 mb/d in 2035 (including its share of output from the Neutral Zone). Sustainable crude oil production capacity has been raised to a little over 12 mb/d with the recent completion of the 1.2-mb/d Khurais field development. The next major development, the 900-kb/d Manifa field, will be completed by around 2016, but this will probably not increase overall capacity, due to declines in output at other fields (IEA, 2010b). The Kingdom has stated for several years that it is capable and willing, if there is sufficient market demand, to increase crude oil production capacity to 15 mb/d and to sustain that level for 50 years, though it has no plans to exceed that capacity. NGLs production is projected to rise from 1.3 mb/d in 2009 to 2.2 mb/d 9. Our projections of OPEC production are based on assumptions that adequate investment is forthcoming. See IEA (2008) for a detailed discussion of the uncertainties surrounding future OPEC investment and production policies.

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by 2035 in line with the expansion of gas production. The projected level of overall production, even in 2035, would still leave Saudi Arabia with a modest amount of spare capacity. The stated policy goal in this respect is to maintain around 1.5 to 2.0 mb/d of spare capacity on average, which would enable Saudi Arabia to continue to play a vital role in balancing the global oil market. Oil production in Qatar will continue to be driven by gas exports, thanks to its supergiant North gas/condensate field. We expect more LNG export capacity to be added and to see a resurgence of interest in GTL, beyond the current Oryx and Pearl plants, as a hedge against decoupling of gas and oil prices. As a result of increased gas production, NGLs production will exceed crude oil production in Qatar from 2010 onwards. Box 3.5 z The renaissance of Iraqi oil production Over the last two years, the gradual normalisation of the political situation and improved security in Iraq have enabled the country to stabilise oil production at around 2.5 mb/d and to hold two bidding rounds for licenses, which provide for the participation of foreign oil companies in the development of the country’s abundant oil resources (IEA, 2010b). Eleven different field development projects have been agreed so far, including the rehabilitation of some existing fields, notably the Rumaila field in the south of the country, and the more intensive development of fields that have as yet barely been exploited, including the super-giant Majnoon field — the 25th largest field in the world (Table 3.6). Were all these projects to proceed on schedule, Iraqi oil production capacity would reach more than 12 mb/d by 2017. This would involve more than $160 billion of investment. The sheer scale of this, coupled with political and security-related uncertainties, suggests that the expansion of capacity will, in practice, be much slower. In the New Policies Scenario, we expect that it will take until the 2030s for Iraqi oil production to exceed even 6 mb/d. Although ambitious work has started on several of the projects, much basic infrastructure, including roads, bridges, airports, power and water supply is in need of repair and expansion. Existing export routes are fully utilised and a major expansion of the shipping ports will be needed even to reach the projected level of production. Iraq’s crude oil production nonetheless overtakes that of Iran soon after 2015 and total oil production (including NGLs) by around 2020.

Iran has significant upside production potential, both for crude oil and NGLs. However, the current political isolation of the country makes it unlikely that this potential will be realised quickly. We project a slow increase in overall oil output during the projection period, in large part driven by NGLs. Kuwait has been making plans for boosting production capacity to 4 mb/d for the last 20 years. These plans, originally known as “Project Kuwait”, called for the involvement of international companies in developing the country’s large heavy oil resources under service contracts, but this approach was halted in the face of political opposition. Officially, the country aims to reach the targeted production level by 2020 — 1 mb/d above current capacity — but achieving this will be contingent on securing the technical 132

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assistance of foreign firms. Emphasis has now shifted away from heavy oil to developing the country’s lighter oil reserves. We project gradually increasing production for most of the period, reaching 3.6 mb/d only by 2035. The United Arab Emirates is also projected to increase production steadily throughout the projection period, remaining an important contributor to the global supply/demand balance. Table 3.6 z Oil production technical services contracts issued in Iraq in 2010 Field Rumaila West Qurma 1 West Qurma 2 Majnoon Zubair Halfaya Garraf Badra Qayara Najmah Missan

Nigeria, where the complex political situation and sporadic civil conflicts over oil resources have hampered investment for several years, also has significant potential for higher production. We project a drop in production in the early part of the Outlook period, but, in the longer term, a rebound in output on the assumption that the investment climate improves. An increase in NGLs production contributes to higher production, as efforts to reduce gas flaring slowly bear fruit. Venezuela sees a modest decline in conventional oil production over the projection period, as its relatively limited resources are depleted and a lack of investment and modern technology take their toll. However, this decline is more than offset by rapid growth in unconventional, extra-heavy oil from the Orinoco belt (see Chapter 4). Other OPEC countries are expected to maintain more or less steady levels of production for a large part of the projection period, variations reflecting their individual resource endowments. Angola’s output, in particular, is limited by its currently estimated ultimately recoverable resources, though new discoveries could alter this picture.

Inter-regional trade in oil (crude oil, NGLs, unconventional oil and refined products) is set to grow markedly over the next quarter of a century in the New Policies Scenario. Rising demand outstrips indigenous production in the main non-OECD importing regions, more than offsetting the drop in demand and imports in the OECD. The volume of trade between the main regions modelled in this Outlook expands from 37 mb/d in 2009 to 42 mb/d in 2020 and 48 mb/d in 2035 (Table 3.8). Over the projection period, the share of inter-regional trade in world oil production rises from 44% to 49%. China and India see the biggest jump in imports in absolute terms: China’s net imports reach almost 13 mb/d in 2035 — up from 4.3 mb/d in 2009. Oil imports in the United States drop from 10.4 mb/d to 7.8 mb/d over the same period; moreover, a growing share of these imports come from Canada (much as synthetic crude, or diluted bitumen, derived from oil sands), so the country’s dependence on suppliers outside the region diminishes even more. The Middle East sees the biggest jump in exports, with much of the increase going to non-OECD Asia. The rise in inter-regional trade does not necessarily make oil supplies less secure. But the growing reliance on supplies from a small number of producers, using vulnerable supply routes, could increase the risk of a supply disruption. Moreover, the growing concentration of the sources of exports would increase the exporters’ market power, and could lead to lower investment and higher prices. Policies to tackle climate change would make a big difference: policy-driven reductions in oil demand in the 450 Scenario cut substantially import needs, though the share of OPEC oil in total supply to importing countries increases slightly (see Chapter 15). 134

Note: Positive numbers denote exports; negative numbers imports. *Per cent of production for exporting regions/countries. **Total net exports for all WEO regions/countries (some of which are not shown in this table), not including trade within WEO regions.

Current trends Worldwide upstream oil investment is set to bounce back in 2010, but will not recover all of the ground lost in 2009, when sharply lower oil prices and financing difficulties led oil companies to slash spending. Worldwide, total upstream capital spending on both oil and gas10 is budgeted to rise in 2010 by around 9% to $470 billion, compared with a fall of 15% in 2009. These investment trends are based on the announced plans of 70 oil and gas companies. Total upstream investment is calculated by adjusting upwards the spending of the 70 companies, according to their share of world oil and gas production for each year. Our survey points to a faster increase in upstream spending in 2010 than in downstream spending (Table 3.9). 10. Upstream investment is not reported separately for oil and gas.

Note: The world total for upstream investment was derived by prorating upwards the spending of the 70 leading companies, according to their share of oil and gas production in each year. Sources: Company reports and announcements; IEA analysis.

Private companies will continue to dominate upstream spending, though national oil companies are set to increase their spending more quickly in 2010 (Figure 3.25). The five super-majors (ExxonMobil, Shell, BP, Chevron and Total) alone account for almost one-fifth of total spending, rising 5% in 2010, with other private companies’ capital 136

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expenditures rising 11%. Spending by the national oil companies is set to rise by 10%, taking their share of world upstream investment to 39%. The trends in investment for 2010 should be treated as indicative only, as they are based on announced plans, which could change were oil prices and costs to differ markedly from our assumptions. Global upstream investment in 2009 is now estimated to have totalled $40 billion more than was budgeted in the middle of the year. The upward revision reflects a surge in spending in the second half of the year, prompted by rising oil prices and a sharp drop in the value of the dollar against most currencies (which automatically increased investment outside North America, expressed in dollars).

Annual upstream investment more than quadrupled between 2000 and 2008, before falling back in 2009. But most of this increase was needed to meet the higher unit costs of exploration and development, as the prices of cement, steel and other materials used in building production facilities, the cost of hiring skilled personnel and drilling rigs, and the prices of oil-field equipment and services soared. According to our Upstream Investment Cost Index, costs doubled on average over the eight years to 2008 (Figure 3.26). They fell back by about 9% in 2009, but are poised to rebound in 2010 by about 5%.

Adjusted for changes in costs, annual global upstream investment only doubled between 2000 and 2008. With nominal investment falling more heavily than costs in 2009, real investment was 90% higher than in 2000 (Figure 3.27). On current plans and cost trends, capital spending in real terms is set to increase by more than 4% in 2010. Recent trends in upstream investment and knowledge of projects now under way — if completed to schedule — point to continuing growth in total oil production capacity (including unconventional sources). Between 2009 and 2015, capacity is set to expand in net terms by around 5 mb/d (IEA, 2010b). In the New Policies Scenario, demand rises by 5.7 mb/d, implying a modest reduction in the amount of effective spare capacity, all of which is in OPEC countries, from above 5 mb/d in 2009 to less than 4 mb/d in 2015. Chapter 3 - Oil market outlook

* Preliminary estimate based on trends in the first half of the year. Note: The Upstream Investment Cost Index, set at 100 in 2000, measures the change in underlying capital costs for exploration and production. It uses weighted averages to remove effects of changes in spending on different types and locations of upstream projects. Sources: Company reports and announcements; IEA analysis.

Upstream investment and operating costs vary with the physiographical location of resources, the geological characteristics of the deposits and multiple regional factors. Finding and development costs and lifting (or operating) costs per barrel of reserves developed and produced are generally lowest for crude oil in the Middle East (Figure 3.28). The future trajectory of these costs will be affected by opposing factors: the development and use of new technologies will facilitate access to more resources and will help reduce unit costs in certain cases, while the depletion of basins 138

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in production increases the effort and expense needed to extract more oil. Cyclical cost variations will also occur as short-term fluctuations in activity and the oil price affect the availability of services and other resources.

Note: Finding and development (F&D) costs are initial capital investments; lifting costs are ongoing operating costs. The profitable price of oil is determined not just by F&D and lifting costs, but also by the cost and rate of capital repayment, taxes, royalties and profit margin. Cost ranges represent average regional values over the three-year period to 2009 per barrel of oil equivalent developed and produced. Some projects fall outside these ranges. Extra-heavy oil includes Canadian oil sands and deposits in the Venezuelan Orinoco belt. Source: IEA databases and analysis.

Investment needs to 2035 The projected trends in oil supply in the New Policies Scenario call for cumulative infrastructure investment along the oil-supply chain of around $8 trillion over 20102035, or $310 billion per year. About 85% of this investment is needed in the upstream. Including upstream investment needs for gas (see Chapter 5) yields a total annual upstream oil and gas capital spending requirement of about $440 billion — slightly less than the $470 billion the industry is planning to spend in 2010. This fall in the overall level of upstream investment, mainly in the latter part of the projection period, is caused by the shift in investment towards the Middle East and other regions, where finding and development costs are generally lower. This, together with lower unit costs as technology progresses, more than offsets cost increases due to resource depletion. Around three-quarters of global cumulative oil investment to 2035 is needed in non-OECD countries in the New Policies Scenario (Table 3.10). Investments in OECD countries are large, especially in the upstream, despite the small and declining share of these countries in world production. In contrast, investment in Middle East countries — the biggest contributor to production growth — accounts for only 12% of total investment, because costs are lowest in this region. Chapter 3 - Oil market outlook

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Table 3.10 z Cumulative investment in oil-supply infrastructure by region and activity in the New Policies Scenario, 2010-2035 ($ billion in year-2009 dollars) Conventional production

*World total includes an additional $241 billion investment in inter-regional transport infrastructure.

There is considerable uncertainty about the prospects for upstream investment, costs and, therefore, the rate of capacity additions, especially after 2015. Few investment decisions that will determine new capacity additions after that time have yet been taken. Government policies in both consuming and producing countries are a particular source of uncertainty. Periodic underinvestment in bringing new capacity on stream, together with time lags in the way demand and investment respond to price signals, tends to result in cyclical swings in price and investment (Figure 3.29). Underinvestment in producing countries, where national companies control all or a large share of reserves, could initially lead to shortfalls in capacity, driving prices higher and increasing price volatility. But this effect is likely to be countered by consuming government policies, aimed at curbing oil-demand growth for reasons of energy security and/or climate change (see Chapter 15). In our judgment, the policies, regulatory frameworks and prices assumed in the New Policies Scenario together provide an investment environment that is consistent with the level of investment projected over 2010-2035, but there will undoubtedly be short periods when investment falls short of that required to balance supply with projected demand. 140

THE OUTLOOK FOR UNCONVENTIONAL OIL Are alternatives to crude coming of age? H

I

G

H

L

I

G

H

T

S

z The role of unconventional oil is expected to expand rapidly, enabling it to meet

about 10% of world oil demand in all three scenarios by 2035. Canadian oil sands and Venezuelan extra-heavy oil dominate the mix, but coal-to-liquids (CTL), gasto-liquids (GTL) and, to lesser extent, oil shales also make a growing contribution in the second half of the Outlook period. In the New Policies and 450 Scenarios, this growth is predicated on the introduction of new technologies that mitigate the environmental impact of these sources of oil, notably their relatively high CO2 emissions. z Unconventional oil resources are huge — several times larger than conventional oil

resources — and will not be a constraint on production rates over the projection period, nor for many decades beyond that. Most of these resources are concentrated in Canada, Venezuela and a few other countries. Production will be determined by economic and environmental factors, including the costs of mitigating emissions. z The cost of production puts unconventional oil among the more expensive

sources of oil available over the Outlook period; unconventional oil projects require large upfront capital investment, typically paid back over long periods. Nonetheless, its exploitation is economic at the oil prices in all three scenarios and unconventional oil, together with deepwater and other high-cost sources of non-OPEC conventional oil, is set to play a key role in setting future oil prices. z The production of unconventional oil generally emits more greenhouse gases per

barrel than that of most types of conventional oil. However, on a well-to-wheels basis, the difference is much less, since most emissions occur at the point of use. In the case of Canadian oil sands, CO2 emissions are between 5% and 15% higher. Mitigation measures will be needed to reduce emissions from unconventional oil production, including more efficient extraction technologies, carbon capture and storage (CCS) and, in the case of CTL, the addition of biomass to the coal feedstock. Improved water and land management will also be required to make the development of these resources and technologies socially acceptable.

z CTL, if coupled with CCS, has the potential to make a sizeable contribution in

all three scenarios; many of the large coal-producing countries are investigating new projects, but clarification of the legal framework for CCS will most likely be required before they can proceed. Renewed interest in new GTL plants is expected, with major gas producers seeing GTL as a way to hedge the risks of gas prices remaining weak relative to oil prices.

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Introduction Unconventional oil is set to play a key role in the oil supply and demand balance and so in determining future oil prices (Chapter 3). However there are many challenges surrounding the development of unconventional oil supplies:  Total development costs are often higher than those for conventional oil resources.  Developments are capital-intensive with payback over long time periods, so the

timely availability of enough capital has been questioned.  Resources are relatively localised, casting doubts on the availability of labour and a

supporting social infrastructure.  CO2 emissions for extracting and upgrading oil from unconventional sources are

currently larger than those from most conventional sources, so production will be affected by climate policies.

 A large fraction of the world’s unconventional resources is located in environmentally

sensitive areas, where water and land use could constrain new developments. The uncertainties surrounding the response to these challenges are reflected in large differences in the share of unconventional oil in world oil supply in the three scenarios (Table 4.1). In particular, the attractiveness of investing in unconventional oil is highly sensitive to the outlook for oil prices, the extent of the introduction of penalties on CO2 emissions and the level of development costs relative to conventional oil. In the New Policies Scenario, unconventional sources play an increasingly important role in supplying the world’s oil needs. The main sources of unconventional oil today — Canadian oil sands and Venezuelan extra-heavy oil — continue to dominate over the projection period, with other sources just beginning to play a role near the end of the projection period. Unconventional oil supply grows more rapidly in the Current Policies Scenario, in line with higher oil prices (which boost the economic attractiveness of the high-cost unconventional sources). In the 450 Scenario, oil demand is relatively weak and the large CO2 penalty further depresses demand for unconventional oil, though production from Canadian oil sands and of Venezuelan extra-heavy oil, nonetheless increases beyond current levels. Coal prices, being depressed even more than oil prices, make coal-to-liquids production (with carbon capture and storage) relatively attractive. Table 4.1 z World unconventional oil supply by type and scenario (mb/d)

* Refinery additives and blending components (see the discussion at the end of this chapter).

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What is unconventional oil? There is no universally agreed definition of unconventional oil, as opposed to conventional oil. Roughly speaking, any source of oil is described as unconventional if it requires production technologies significantly different from those used in the mainstream reservoirs exploited today. However, this is clearly an imprecise and timedependent definition. In the long-term future, in fact, “unconventional” heavy oils may well become the norm rather than the exception. Some experts use a definition based on oil density, or American Petroleum Institute (API) gravity. For example, all oils with API gravity below 20 (i.e. a density greater than 0.934 g/cm3) are considered to be unconventional. This definition includes “heavy oil”, “extra-heavy oil” (with API gravity less than 10) and bitumen deposits. While this classification has the merit of precision, it does not always reflect the technology used for production. For example, some oils with 20 API gravity located in deep offshore reservoirs in Brazil are extracted using entirely conventional techniques. Other classifications focus on the viscosity of the oil, treating as conventional any oil which can flow at reservoir temperature and pressure without recourse to viscosity-reduction technology. But such oils may still need special processing at the surface if they are too viscous to flow at surface conditions. Oil shales are generally regarded as unconventional, although they do not fit into the above definitions (more details on oil shales can be found later in this chapter). Also classified as unconventional are both oil derived from processing coal with coal–to-liquids (CTL) technologies and oil derived from gas through gas-to-liquids (GTL) technologies. The raw materials in both cases are perfectly conventional fossil fuels. These oil sources are discussed briefly later in this chapter. Oil derived from biomass, such as biofuels, or biomass-to-liquids (BTL, whereby oil is obtained from biomass through processes similar to CTL and GTL) are sometimes included in unconventional oil, but not always. Another approach, used notably by the United States Geological Survey (USGS), is to define unconventional oil (or gas) on the basis of the geological setting of the reservoir. The hydrocarbon is considered conventional if the reservoir sits above water-bearing sediments and if it is relatively localised. If neither is the case, for example if the hydrocarbon is present continuously over a large area, the hydrocarbon is defined as unconventional. This type of definition has a sound geological basis, but does not always reflect the technology required for production, nor the economics of exploitation. For the purpose of this Outlook, we define as unconventional the following categories of oil:1  Bitumen and extra-heavy oil from Canadian oil sands.

 Extra-heavy oil from the Venezuelan Orinoco belt. 1. This definition differs from that used in the IEA Oil Market Report (OMR), which includes some but not all of the Canadian oil sands and Venezuelan Orinoco production (it includes upgraded “synthetic” oil, but not raw bitumen or extra-heavy oil). The OMR also includes biofuels, but these are included in biomass in the WEO. The OMR definition is driven primarily by the way the production data is reported by various countries and the short time available for making adjustments to monthly figures. The definitions we have adopted here are primarily to facilitate the discussion of long-term issues.

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 Oil obtained from kerogen contained in oil shales.  Oil obtained from coal through coal-to-liquids technologies.  Oil obtained from natural gas through gas-to-liquids technologies, as well as refinery

additives and gasoline blending additives originating primarily from gas or coal, such as methyl tertiary butyl ether (MTBE), or methanol for blending. There are bitumen and extra-heavy oil deposits in countries other than Canada and Venezuela (Table 4.2), but only Canada and Venezuela are likely to play a significant role in the exploitation of these resources in the timescale of these projections. This is because of the size of their resources and the facts that they are already in production, plans exist for their further development, significant reserves are considered as proven and they are geographically concentrated; their decline is not an issue over the 25-year horizon of these projections. Their development is much more like a manufacturing operation than a traditional upstream oil industry project. Whether or not they will be exploited is mainly a matter of economics and capital spending dynamics, not one of geology. By contrast, the resources in Russia and Kazakhstan, which are also sizeable, are more geographically dispersed and, with large conventional oil resources still available, there is little incentive to develop these heavy oils quickly. Their production potential in the next 25 years is not large enough to affect world supply significantly. They are briefly discussed in this chapter, but do not feature as part of our unconventional oil production estimates up to 2035.

* As reported by the Oil & Gas Journal (O&GJ, 2009); the national oil company, PDVSA, currently reports 130 billion barrels as proven (as discussed later in this chapter). ** From BGR (2009); Russian authors report significantly smaller resources, of the order of 250 billion barrels; the same applies for Kazakhstan. Bitumen resources in particular are poorly known, as a high percentage is located in the vast and poorly explored region of eastern Siberia. BGR reports 345 billion barrels recoverable, which is more in line with Russian publications. Sources: BGR (2009); USGS (2009a); IEA analysis.

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Box 4.1 z How oil is formed A basic understanding of the formation of oil reservoirs is helpful in understanding the differences between the types of unconventional oil presented in this chapter. Oil deposits result from the burial and transformation of biomass over geological periods during the last 200 million years or so. The biomass is typically contained in a type of sediment called shale (though its mineral composition can vary), deposited at the bottom of the ocean or lake basins. As those sediments get buried, the biomass is transformed into complex solid organic compounds called kerogen. When the sediments are deeply buried, the temperature may be sufficient for the kerogen to be transformed into oil and gas. Under pressure, the oil (or gas) can be expelled from the shale sediments where they were created (known as source rocks) and begin to migrate upwards (due to their low density) into other sedimentary rocks, such as sandstone or carbonates. This upward migration stops when the oil encounters a low permeability rock that acts as a barrier to its movement (cap rock). In this way, a conventional oil reservoir is formed. When the oil does not encounter any significant barrier until it gets near the surface, it can become more and more viscous, as the temperature decreases and some of the lighter components of the oil seep to the surface, where they are degraded by bacteria and escape to the atmosphere. The remaining very viscous oil can become almost solid and stop migrating, even in the absence of a strong cap rock, forming relatively shallow deposits of very viscous, extra-heavy oil or natural bitumen. Occasionally, it can even seep out to the surface, as seen in tar pits, for example.

Production from Canadian oil sands is set to continue to grow over the projection period, making an important contribution to the world’s energy security. Just how rapidly will depend on a number of factors, including whether the environmental impact can be mitigated through the use of new technology without rendering the oil uneconomic. Extraction involving the injection of steam via wells into the oil-sands deposit to reduce the viscosity of the oil and allow it to flow to the surface (in-situ projects, see below) is economically and environmentally preferable, but mining is an alternative and significant mining capacity is under construction which will ensure mining remains a substantial contributor to production growth. In the New Policies Scenario, oil-sands production climbs from about 1.3 million barrels per day (mb/d) in 2009 to 4.2 mb/d in 2035,2 with around two-thirds of the increase coming from in-situ projects (Figure 4.1). The 450 Scenario projects only modest additions to current capacity: projects currently under construction or being planned would suffice to match supply to demand. The Current Policies Scenario calls for rapid growth in 2. This is marketed production, actually part raw bitumen, part upgraded synthetic crude oil. Raw bitumen production is higher, due to volume loss during upgrading; for example in 2009, raw bitumen production was 1.49 mb/d.

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oil sands production, although still below what could be achieved with the projects already proposed. The critical drivers and uncertainties surrounding the prospects for oil-sands production are discussed in detail below.

mb/d

Figure 4.1 z Canadian oil-sands production by type in the New Policies Scenario 5

Very large deposits of very viscous oil and bitumen — oil sands — exist in Canada at relatively shallow depth. They cover a vast region of Alberta and, to a lesser extent, Saskatchewan. The term “oil sands” is a slight misnomer, as the oil or bitumen is found not only in sand formations, but also in carbonates. The main centres of activity are the Athabasca, Cold Lake and Peace River districts (Figure 4.2), though there are also significant resources in neighbouring regions of Saskatchewan. The total oil in place is estimated to be in excess of 2 trillion barrels, as much as the remaining technically recoverable conventional oil in the entire world. However, because of its very high viscosity, this oil is difficult to produce and, with current technology and oil prices, only part of this volume is thought to be recoverable. The Alberta provincial government currently recognises 170 billion barrels as established reserves, i.e. currently economically and technically recoverable. Because they outcrop over a large area, the presence of bitumen in the Canadian oil sands has been known for centuries. Various early attempts at industrial exploitation took place during the 20th century, leading to the refinement of the techniques for mining and bitumen/sand separation. The modern era for the oil sands started in 1967 with the opening of the Great Canadian Oil Sands base mine, the first large-scale mining operation. It has since been expanded to what is now the Suncor Corporation Steepbank/Millenium mine. In-situ primary production, began in the 1970s and the first steam-stimulation projects in the 1980s. Quantification of reserves in the 1990s, as well as the new oil sands royalty regime introduced in Alberta in 1997, paved the way for the boom of the 2000-2008 period, when many new projects were launched and extensive exploration/appraisal land leases were granted. 148

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Figure 4.2 z Main Canadian oil-sands districts

Yukon Northwest Territories

Peace River oil-sands area

Nunavut Peace River

CANADA

Alberta British Columbia Edmonton

Saskatchewan

Fort McMurray Wabasca

Athabasca oil-sands area

Manitoba Lac La Biche Cold Lake

Calgary

Bonnyville Edmonton

UNITED STATES

Bruderheim

Cold Lake oil-sands area

The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA.

There are two main methods used to produce oil sands:  Mining: Part of the Canadian oil sands outcrop to the surface and therefore can be

mined by essentially conventional strip-mining techniques. Some 7% of the total oil originally in place is estimated to be mineable, i.e. some 130 billion barrels. Of the 170 billion barrels of the total Canadian oil-sands established reserves, about 20%, or 35 billion barrels, is recoverable by mining. The “ore”, a mixture of bitumen and sand, is treated with hot water to separate out the bitumen. The remaining sludge of slightly oily sand/clay/water mixture is left to settle in large tailing ponds. Some of the solids may eventually be used as part of land reclamation programmes, while some of the water is recycled.

A small part can be produced by conventional oil-production techniques. For the very viscous oil found in the Canadian oil sands, these techniques can be applied only to the deepest deposits of slightly lower viscosities, and even there recovery is proportionately small, typically less than 5%. However, production costs can be very low. In some fields, polymer flooding is also applied, with a polymer solution being injected through wells to help push the viscous oil towards the producing wells. A variant on primary recovery is called Cold Heavy Oil Production with Sand (CHOPS), in which the production rate is large enough to entrain sand with the oil, with the oil and sand then being separated at the surface using technologies similar to those used in mining. These “cold” recovery techniques currently produce close to 250 thousand barrels per day (kb/d). Most of the oil in the oil sands is too viscous to be produced naturally by such primary, or even polymer-flooding, approaches. The temperature of the oil needs Chapter 4 - The outlook for unconventional oil

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to be increased, so that its viscosity decreases, before it begins to flow out of the reservoirs. The method of choice to heat-up the reservoir is to inject hot steam (at a temperature of 250-350°C). There are numerous variants on steam-injection technologies. Cycling Steam Stimulation (CSS) injects steam in a well for a while then, when the reservoir temperature around the well has risen sufficiently, it turns the well into a producer, produces the heated oil, and then starts again — an approach sometimes dubbed “huff-and-puff”. Steam Assisted Gravity Drainage (SAGD), which has become the most popular technology for new in-situ projects, uses a pair of horizontal wells, one above the other in the reservoir. Steam is injected in the top well and oil accumulates by gravity in the bottom well. Other approaches to providing heat are at an early stage of experimentation, for example, driving an electrical current through the reservoirs or injecting air to burn some of the oil in-situ (toe-to-heel air injection, [THAI] using horizontal wells; combustion overhead gravity drainage [COGD] using a combination of vertical and horizontal wells; or the older fire-flood technique, using vertical wells). Other experimental approaches use solvents (the so-called VAPEX process), or a combination of steam and solvents, to reduce the viscosity of the bitumen. At the beginning of 2010, there were more than 80 oil-sands projects in operation, with total raw bitumen capacity of 1.9 mb/d (Table 4.4). Total production in 2009 averaged 1.5 mb/d of raw bitumen. Projects under construction will add a further 0.9 mb/d capacity by 2015. If all proposed and announced projects were to be completed, another 4.5 mb/d capacity would be added. Production will continue to be dominated by a few large projects, operated by large companies. Mining and in-situ current capacities are about equal, but more incremental capacity will derive from in-situ projects, which are regarded as providing better financial returns and facing fewer environmental problems. Very few new projects are planned using primary production only: although financially attractive, they provide only short-term returns, as the recovery rate is low and production declines rapidly. Production costs depend on the production method, the quality of the reservoir, the size of the project and the location (Table 4.3). Generally, expansions of existing projects cost less than new green-field developments. The profitability of oil-sands projects depends on many variables, including the bitumen/conventional oil price spread, gas prices, construction costs and the prices of steel and oilfield services and labour. At mid-2010 values for these variables, most new oil-sands projects are thought to be profitable at oil prices above $65 to $75 per barrel. Table 4.3 z Typical costs of new Canadian oil sands projects

The current narrow price spread between conventional light oil (such as West Texas Intermediate [WTI]) and Canadian bitumen blends is likely to persist, as refineries 150

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in the United States are geared to process relatively heavy crude and will continue to need Canadian bitumen to balance their crude input slate. The construction of a pipeline from Alberta to the Pacific coast in British Columbia, currently under consideration, would give support to the price of bitumen by opening the Asian market for Canadian bitumen. However, both the proposed pipeline to the Pacific coast and another proposed pipeline to the United States face strong opposition on environmental grounds. Delays or outright cancellation of these projects could affect the marketability of Canadian bitumen. As oil prices increase, as assumed in each of the three scenarios presented in this Outlook, some of the costs, notably of gas and services, will also rise, so the price threshold for profitability will also increase; but analysis suggests internal rates of return could continue to increase over the next 25 years (Biglarbigi et al., 2009, where a similar analysis is done for oil shales). Technological progress and learning would further boost profitability. Most projects are economic while oil (West Texas Intermediate) is priced at more than $80/barrel, but many become uneconomic when the price drops below $50/barrel. This is why many new projects were delayed at the end of 2008 and the beginning of 2009. By mid-2010, when the oil price had rebounded to around $70/barrel, many projects were being reactivated. Overall, the breakeven oil price for Canadian oil-sands projects is comparable to that of deepwater offshore conventional oil projects, but production, and therefore investment payback periods, is spread over a much longer time period.

Upgrading As the oil produced, whether by mining or by in-situ techniques, is extremely viscous (several 100 000 cP,3 or 100 000 times the viscosity of water, is typical), it cannot be transported economically to refineries without pre-treatment. Two solutions are used in the Canadian oil sands: dilution and upgrading.

In the dilution approach, the viscous bitumen is mixed with light hydrocarbons, for example, the NGLs associated with gas production or synthetic crude oil (SCO) from the upgraders. This yields a mixture, sometimes called Dilbit (for “diluted bitumen”), or SynDilBit if diluted with SCO, that can be transported by pipeline to a refinery in the same way as conventional oil. Not all refineries are equipped to process Dilbit, as the bitumen contains a high concentration of sulphur and asphaltenes, beyond the specifications of some refineries. When the Dilbit is delivered to a nearby refinery, the diluting fluid can often be recycled, transported back to the diluting plant and reused. When the diluted bitumen goes to refineries farther away, reuse of the diluting fluid may not be economic. Availability of enough diluting fluid to cater for a significant rise in production of bitumen is likely to require new long-distance pipelines and increased imports, as NGLs production in western Canada is set to decline (IEA, 2010).

3. A centipoise (cP) is a unit of measurement for dynamic viscosity (equal to one-hundredth of a poise). Water at 20°C has a viscosity of 1 centipoise.

Sources: IEA analysis of public documents. Project names and operators may change as properties are traded. Capacity and start dates are indicative only; at the end of 2008 and beginning of 2009, many projects were put on-hold, as companies needed to reduce investments rapidly as the financial crisis deepened. Since the end of 2009, many of those projects have been revived, but exact new schedules are still being elaborated. Actual production is typically 20% below capacity due to maintenance, downtime and incidents.

In the upgrading approach, the bitumen is processed locally in an upgrader to produce synthetic crude oil (SCO), with a composition similar to that of conventional crude oil. This can be used by most refineries. An upgrader is basically a refinery with limited functionality; its role is to reduce the carbon content of the bitumen, either by removing carbon (coking), or by adding hydrogen (hydrocracking). In the former process the excess carbon is recovered as solid coke that can be sold as such or burnt to provide energy locally (with corresponding CO2 generation). In hydrocracking, hydrogen (originally coming from steam or from natural gas) is added to the hydrocarbon chains, increasing the energy content of the oil. This requires energy inputs, emitting CO2 in the process (if the energy comes from fossil fuels). Upgraders require very large capital investment, typically in excess of $60 000 per barrel per day (b/d) of capacity. Most mining operations and a few in-situ projects have an associated upgrader. Smaller in-situ operations cannot justify this level of capital investment and use the dilution approach or send bitumen to off-site upgraders. New experimental technologies for small-scale upgraders, such as the Ivanhoe HTL (Heavy-to-Light) system, are being tested on a pilot scale and may allow more of the smaller in-situ projects to produce SCO, a higher value product. Integrating upgraders into the in-situ operation promises to reduce the need for natural gas to produce the steam required by CSS or SAGD processes. Indeed the Nexen/Opti Long Lake project has developed a process in which the heavy residues from the upgrader are gasified to provide energy for the steam generators. Availability of natural gas for the steam generators, otherwise, is one factor that could limit the growth of production from the oil sands, although the current gas glut, linked to the shale gas revolution in North America, has reduced these concerns. Certainly, producing 2.5 mb/d from in-situ SAGD technology, as projected for 2035 in the New Policies Scenario, with a steam-oil-ratio (the volumetric ratio of injected steam to produced oil) of 3 (typical of most projects today) would consume more than 28 bcm/year of gas, if all the energy required came from gas. This compares with total gas production in Canada of 161 bcm in 2009. Alternatives to the Nexen/Opti approach are to use nuclear, wind, or geothermal energy. Various projects along these lines have been discussed, but none are nearing the point of decision. New in-situ production technologies, such as the use of solvents, have the potential to reduce significantly the need for steam. THAI and other experimental in-situ combustion approaches can even do away with any steam usage, in a sense obtaining the equivalent energy from the bitumen itself.

Availability of capital and labour Before the financial crisis of 2008-2009, many oil-sands projects were planned. Several new small companies were created, borrowing capital to develop those projects. This led to an overheating of the economy in the Alberta Fort McMurray region, with rapid cost inflation, labour shortages and saturated infrastructure. The financial crisis has put many projects on hold, with smaller companies now considering alternative business approaches. Some consolidation has taken place already. However, as the economic recovery takes hold, many projects are being revived. This raises the possibility that overheating, cost inflation, labour shortage and competition for capital may return to the oil sands region, leading to another down-cycle. By mid-2010, the number of Chapter 4 - The outlook for unconventional oil

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workers living in camps in the Fort McMurray region had already passed the previous peak in 2008 and housing costs were at an all-time high. It is estimated that each 1 mb/d of new capacity requires an additional 20 000 direct employees. Attracting enough skilled labour for new projects is likely to be a challenge in the coming years, with a risk of cost overruns and project delays. Assuming a weighted average of mining, in-situ and upgrader investment costs of $70 000 per b/d, the capital required to bring production from the oil sands to the level of 3.3 mb/d in 2025 projected in the New Policies Scenario is estimated at around $11 billion per year. This is in-line with what has been spent in the last few years, but remains large compared with total current investment in Canada of about $230 billion/year 4 (though it is relatively small as a percentage of capital investment in the global upstream oil and gas industry of around $470 billion in 2010). Growing investment in the oil sands by Japanese, Korean and, to a larger extent, Chinese oil companies (for example, in 2010, Sinopec acquired the 9% of Syncrude previously owned by ConocoPhillips) is likely to alleviate capital availability constraints.

CO2 emissions CO2 emissions from oil-sands production are higher than those associated with conventional oil production for two reasons:  Large amounts of energy are used to produce the steam for in-situ production or the

hot water for bitumen/sand separation in mining operations. Most of this energy is currently supplied by burning natural gas.5  Added CO2 emissions per energy unit supplied result from the fact that the process

starts from a carbon-rich fluid. These additional emissions come from energy used during upgrading (if supplied by natural gas), the use of coke (produced in upgraders), or higher energy use in refineries during processing of bitumen to produce the same amount of standard gasoline, diesel or naphtha.

Life-cycle emissions, taking account of all stages of the supply of oil, comprise:  Emissions during the oil-production processes (upstream emissions).  Emissions during upgrading and transport to the refinery gate.

The sum of these first two components makes up the “well-to-refinery” emissions.

 Emissions incurred in refineries and in transporting finished products to market.

4. Yearly investment in non-residential construction, machinery and equipment. 5. Several of the steam plants actually co-generate heat and electricity. This provides electricity with a lower carbon footprint than the average electricity mix of Alberta. We do not account for the corresponding reduction of CO2 emissions in the discussion in this chapter, as the electricity mix of the region could change in the future, independently of the production from oil sands.

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The sum of these first three components makes up the “well-to-tank” emissions.  Emissions during the use of the products (typically combustion in an engine).

The sum of all four components makes up the “well-to-wheels” emissions. Our analysis of independent estimates is presented in terms of well-to-wheels emissions of carbon dioxide equivalent (CO2-eq) per barrel of crude (Figure 4.3). Box 4.2 discusses various ways to present life-cycle emissions. Emissions from oil-sands production vary with the maturity of the project: for example, in the early phases of SAGD projects, the steam-oil ratio can be very high and, therefore, the CO2 emissions per barrel also high, but they tend to fall as the project matures. CO2 emissions are, of course, different for mining projects and for in-situ projects. Our analysis shows that the well-to-wheels emissions of oils sands are slightly higher than for most other oils, the relatively-low difference being explained by the fact that emissions are dominated by the end-use (combustion) of the fuel. The difference ranges from zero to about 15%. Figure 4.3 z Well-to-wheels greenhouse-gas emissions of various oils Oil sands in-situ high

Combustion

Oil sands in-situ low

Refining

California heavy

Upgrading & transport

Nigeria

Production

Oil sands mining

US Gulf Coast Iraq Mexico Venezuela Saudi Arabia 0

100

200

300

400 500 600 700 Kilogrammes of CO2-eq per barrel of crude

Note: Transport emissions are based on delivery to the United States. The bottom seven bars are examples of specific conventional crudes; they do not imply an average value for the countries of origin. The range of values for in-situ production of oil sands is indicated by the high and low cases.

In principle, emissions from production of oil sands ought to be compared with those from alternative sources of oil that oil sands might be displacing, such as conventional oil from Arctic locations or deepwater. These are likely to be at the high end of the current range of emissions for conventional oils. The production-related (upstream) emissions from those conventional sources can vary greatly, ranging from 10 kilogramme (kg) of CO2-equivalent/barrel of crude for Arabian Light from Saudi Arabia to 100 kg CO2-eq/barrel of crude for Nigerian Bonny Light. These figures compare to typical production-related emissions of about 80 kg CO2-eq/barrel for crude from in-situ oil sands and 40 kg for oil-sands mining. It is arguably more meaningful to compare the well-to-tank emissions, i.e. to include emissions from upgraders and refineries (for Chapter 4 - The outlook for unconventional oil

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oil sands, only the sum of the two is meaningful, as the degree of upgrading before transport to refineries can vary). Well-to-tank emissions range from 100 to 190 kg CO2-eq/barrel for conventional oil, compared with typical values of 160 kg for oil-sands mining and 200 kg for oil sands in-situ production (Californian heavy crude generates even higher emissions than oil sands). It is clear that some regions produce conventional oil with CO2 emissions similar to those of unconventional oil from Canadian oil sands. The large CO2 emitters are primarily regions, such as Nigeria, where large amounts of associated gas are flared, due to the lack of markets for such gas. Reduced gas flaring would lead to a convergence of CO2 emissions from conventional oil production towards the value typical of the more mature production areas, though increased production of heavy conventional oil resources would offset this factor to a small degree. Box 4.2 z Life-cycle emissions

Life-cycle emissions analysis can be carried out for specific oil products, such as gasoline or diesel, or for the barrel of oil as a whole. Analysis of a product looks at emissions incurred during its production and use, including emissions from the production of the crude needed as feedstock. They can be reported in kilogrammes of CO2-eq per barrel of diesel or gasoline or per mile driven, or kg of CO2-eq per megajoule (MJ) of product. Actual emissions depend on the final product in question; for example, they differ for gasoline and diesel. This is useful when looking at fuel standards. One can compare diesel coming from different crude feedstocks: those coming from oil sands feedstock typically have 10% higher well-to-wheels emissions than those coming from average conventional oil. Analysis of crude oil looks at emissions incurred during production and subsequent transformation and use of a barrel of crude. It is also reported in kg of CO2-eq per barrel or per MJ of crude. Crudes of different origins differ according to the emissions incurred during production and refining, but they also differ in emissions coming from end use, because different crudes give different product slates at the refinery exit door. For example, bitumen from Canadian oil sands could have low life-cycle emissions because it produces a lot of coke that is used for landfill (as is sometimes practised for coke produced in upgraders) rather than burnt. Similarly a light oil could have high emissions because it produces mostly gasoline and middle distillates and little tar or petrochemicals. So life-cycle emissions comparisons between different crudes can be difficult to interpret. Instead of a full life-cycle analysis, we present emissions per barrel of crude, assuming the emissions from end-use are the same for each crude and equal to those of the combustion of an average crude (Figure 4.3). A similar approach is used in CERA (2009). Of course, technological improvements are likely to reduce CO2 emissions per barrel of oil produced from oil sands over the projection period, for example through more efficient use of steam in SAGD or CSS, solvent-based technologies, replacement by nuclear or renewable energy of the natural gas used to supply the energy for steam 158

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generation, in-situ combustion techniques and carbon capture and storage (CCS) of the concentrated CO2 emissions from upgraders. Some of these technologies (for example, nuclear power or CCS) could bring the CO2 emissions close to zero. However, they require large investments and long construction times and are therefore likely to have a significant impact on emissions only towards the end of the projection period. Other approaches, mainly involving efficiency improvements, will undoubtedly be implemented progressively and achieve reductions in productionand-upgrading related emissions. Taking account of the evolution of the mix between mining and in-situ, we project the average differential in well-to-tank emissions between oil sands and conventional oil to fall from about 50 to about 40 kg CO2-eq/barrel over the period 2009-2035. This represents “extra” CO2 emissions of 60 Mt CO2 annually for the 4 mb/d of oil-sands production projected in the New Policies Scenario for 2035 (vis-à-vis conventional oil production).6 Although this is not large compared with current worldwide CO2 emissions of 30 Gt/year, it is significant on the scale of Canada’s emissions of 550 Mt/year and clearly creates a significant national challenge. The extra 60 Mt would be equivalent to 4% of the projected US transport-related emissions of more than 1.5 Gt CO2 in 2035. Our estimated emissions differential of 40 kg CO2-eq/barrel can be translated into an extra “cost” for bitumen from the oil sands. At $50/tonne of CO2 (the projected price of CO2 in 2035 in the New Policies Scenario) the higher emissions represent an extra $2/barrel, which does not significantly affect the economics of oil sands at the oil prices assumed in this scenario. At $120/tonne of CO2 (the projected price in the 450 Scenario in 2035) the additional production cost would be $5/barrel, which, coupled with the reduced oil price of the 450 Scenario, would make the economics of new oil-sands projects marginal and cast doubt over the most expensive projects. However, it is likely that the cost of CCS with CO2 captured from some concentrated sources, such as the upgraders or the hydrogen plants, would be significantly less than $120/tonne (although it is early to attempt estimates, figures of around $50/tonne have been suggested). Pilot projects are planned, with support from the Alberta public authorities and the Canadian government; in particular the Quest project will capture 1 Mt of CO2 per year from the Shell Scotford upgrader. Part of the CO2 will be stored in a nearby deep aquifer and part may be made available for CO2 enhanced-oilrecovery (EOR) projects elsewhere in Alberta. In another pilot, CNRL plans to capture CO2 at its hydrogen plant and use it in management of tailings ponds at its Horizon mining facilities, effectively storing it as carbonate mineral. Success of these pilot projects in the next three to four years could lead other upgraders to follow the same approach, with CCS removing up to 20 Mt/year from oil-sands emissions by 2025.

Water usage Another potential constraint on future production from Canadian oil sands is the availability of water. Mining operations use hot water to separate the bitumen from 6. For the purpose of projecting CO2 emissions from conventional oil production, we assume an average of 30 kg CO2eq/barrel over the projection period. Chapter 4 - The outlook for unconventional oil

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the sand. Current operations use 2 to 3 barrels of water per barrel of bitumen produced (bw/bo), net of recycling of tailings ponds water. The water is typically taken from local rivers. Water can also be used during the upgrading process, bringing the mining plus upgrading use to 3 to 5 barrels of water per barrel of SCO. In-situ operations use water to produce steam for CSS or SAGD processes. Typical usage is 8 bw/bo produced, but a large part of the water is recycled, so that for ongoing production the average net water requirement is closer to 1 bw/bo. Currently, about 50% of that water comes from freshwater, but more and more projects take water from underground saline aquifers. Water extraction from local rivers is regulated and limited to 3% of river flow (and less at times of low water flow); but even that amount is considered by some to be potentially damaging to the river ecosystems. Clearly, large increases in production from the oil sands will depend upon significant reductions in river-water usage. Reductions in water needs could come from:  An improved steam-oil ratio in SAGD/CSS production.  Increased production from steam-less processes, such as primary, solvent-based, or

out of shallow saline aquifers has not yet been fully assessed and more studies are underway to ensure this can be done without harmful ecological effects.  Increased recycling of water. For example, the possibility of recycling water from

mining operations into the in-situ operations is being considered. Improvements in tailings management, such as more rapid separation of solids and water, would ease recycling. In addition to water usage, pollution of rivers and water tables has been attributed to production of oil sands. Rigorous monitoring is required by regulation and performed. However, recently, abnormal concentrations of (unregulated) polycyclic aromatic compounds have been detected downstream of mining operations and even near some in-situ operations (Kelly et al., 2009). These compounds, possibly toxic to water wildlife, are naturally present in the outcropping oil sands but may be released during extraction operations and land disturbance. Proper monitoring and prevention of seepage from tailings ponds, or bird deterrence near tailing ponds, are required components of proper protection of ecosystems.

Land usage Most of the Canadian oil-sands deposits are located in the environmentally sensitive Canadian boreal forest. The total oil-sands area occupies about 140 000 square kilometres (km2) of northern and eastern Alberta. The Alberta boreal forest occupies about 380 000 km2 (part of the 3 million km2 total Canadian boreal forest). 160

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Mining operations have a large impact on the landscape. A typical mine clears about 80 km2 of land per billion barrels of production. Sustained mining production of 1.5 mb/d over 20 years, as projected in the New Policies Scenario, would require about 900 km2 of land to be cleared. Mining companies are required to reclaim the land after 20 years, though there is controversy over the impact on ecosystems even after reclamation. Mining activities in the oil sands have so far disturbed 602 km2, of which 65 km2 have been reclaimed (and only 1 km2 has so far been certified as reclaimed by the regulatory authorities). In-situ projects have a smaller footprint, but still require some clearing for basic infrastructure, including roads, landing strips, steam plants, steam lines and well pads. Estimates range from 10 to 15 km2 per billion barrels. Sustained production of 2 mb/d for 20 years, again as projected in the New Policies Scenario, would, therefore, disturb about 200 km2. As they tend to be more geographically dispersed, a large number of small projects could give rise to significant concerns for ecosystems, through forest fragmentation and wildlife disturbance. Prospects for reducing the amount of land disturbed are limited, as this is more linked to the density of the resources per km2 than to the technology used for production. Efforts are likely to focus on accelerated reclamation and improvements in reclamation technologies in order to better reconstitute the original ecosystems. Some aspects of land disturbance, such as the tailing ponds created by mining operations, could be alleviated by novel technologies to accelerate the separation of solids and water, a number of which are being tested.

Venezuelan Orinoco Belt With the assumption of no interference from political events, the production of extraheavy oil from the Orinoco Belt in Venezuela is projected to grow to over 2.3 mb/d in the New Policies Scenario (Figure 4.4).7 The growth in output to 2020 could be derived from current capacity and additions that have already been announced. In the Current Policies Scenario, with its larger demand for oil, the Orinoco could compensate for slower growth in Canadian oil-sands production, if Canadian projects were delayed by environmental concerns, provided Venezuela was more ready to accept international capital. Total Venezuelan production does not increase as strongly, as the rise in extra-heavy oil production is offset by the decline in ageing conventional oil fields.

The Venezuela Orinoco oil belt is the second-largest deposit of extra-heavy oil (with an API gravity of less than 10) in the world, after the Canadian oil sands (Table 4.2). The amount of oil in place is estimated to be 1.3 trillion barrels, over an area of about 50 000 km2. Although the deposits are deeper than in Canada, typically 500 to 1000 metres, and therefore the oil is somewhat less viscous at 7. There is uncertainty on the status of Orinoco production with respect to future OPEC production quotas. We have assumed that it would be included in future Venezuelan quotas as per current agreements, but a different approach might allow larger production growth.

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reservoir temperatures (typically of about 55°C), it is still not generally amenable to conventional production techniques. The primary recovery rate with vertical wells is less than 5%; multilateral horizontal wells allow a recovery rate of 10 to 15%; higher recovery rates require thermal methods, such as Cyclic Steam Stimulation or SAGD.

mb/d

Figure 4.4 z Venezuelan oil* production by type in the New Policies Scenario 4

A recent evaluation by the USGS estimated the technically recoverable oil from the Orinoco province to be about 500 billion barrels. Although the USGS has not given any estimate of economically recoverable resources, it is likely that a large fraction of that volume is economically recoverable at current prices. Petroleos de Venezuela (PDVSA), the national oil company, launched in 2006 the Magna Reserva project to certify reserves in the Orinoco. By early 2010, 133 billion barrels had been certified, though the Oil & Gas Journal currently reports only 60 billion barrels. PDVSA expects around 230 billion barrels to be proven by the end of the project. Orinoco production started in earnest at the beginning of the 2000s, with several projects contributing to total production of about 700 kb/d in 2005, about two-thirds from primary production from vertical or multilateral horizontal wells and the rest produced with steam stimulation. Capacity remains near that level (Table 4.5), but production fell to around 400 kb/d in 2009 (see Table 4.1, above). Early projects emulsified the extra-heavy oil with water to create a mix, dubbed Orimulsion, which could be transported by pipeline and used as fuel oil in power generation; but all of the production is now upgraded into synthetic crude oil (SCO). Several new projects have been announced which, collectively, would add about 2.3 mb/d capacity by around 2017. Taking into account project lead times and delays, total capacity is unlikely to exceed 2.0 mb/d by 2020. Most of the announced projects involve the construction of upgraders, although they are not always large enough to treat the full production. Deliveries will be a mix of SCO and extra-heavy oil diluted with light hydrocarbons. 162

In principle, production from the Orinoco will face similar challenges to those of in-situ Canadian oil-sands projects, notably the availability of energy for steam generation, the availability of water and CO2 emissions. But there is very little information available on current performance and future plans for reducing the environmental impact. This is an area in which open, joint work between PDVSA and environmental non-governmental organisations would be beneficial. Little recent information is available on the costs of new developments in the Orinoco belt. For steam stimulation projects, technologies are similar to those used at Canadian oil sands in-situ projects, so it can be assumed that the capital and operating costs are similar (Canadian capital costs are around $30 000 to $40 000 per b/d of capacity) (Table 4.3). These costs are roughly in line with the capacity and investment costs quoted at the signing of recent new joint ventures, such as the Junin 6, or Carabobo 1 and 3 agreements. Primary production with multilateral horizontal wells, which gives higher recovery rates than in Canada, due to lower oil viscosity, is significantly cheaper. So, overall, assuming a mix of primary and steam stimulation, new projects would be expected to cost on average about one-third less than Canadian oil-sands projects on a per-barrel basis. Chapter 4 - The outlook for unconventional oil

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Other extra-heavy oil provinces Heavy oil has been produced in other parts of the world for many years, using either primary or thermal techniques (steam stimulation). For example, the Kern River heavy oil area in California has used steam stimulation since 1965, producing more than 1 billion barrels from this technology, and the area still produces around 250 kb/d. The recovery rate in this heavy oil field, typically around 5% with primary production alone, can reach 50% to 70% with steam stimulation. A similar situation applies in the Duri field in Indonesia, the largest steam-stimulation project in the world, which has produced close to 2 billion barrels since 1975 and still produces around 200 kb/d. Heavy oil projects are active or planned in Brazil, in the North Sea, in the Neutral Zone between Saudi Arabia and Kuwait (where Chevron plans production of up to 300 kb/d from steam enhanced oil recovery in the Wafra field) and several other places in the world. China and East Venezuela also have some active steam injection projects. The Pungarayacu heavy oil field in Ecuador may have close to 20 billion barrels of oil originally in place, according to operator, Ivanhoe Energy, which plans to apply its small scale upgrading technology to development of this remote field. In the United States, there are deposits similar to, though much smaller than, the Canadian oil sands, in Utah (with 16 billion barrels of oil originally in place). Congo, Madagascar and a few other countries have small projects in “oil-sands-like” deposits. However, none of these are large enough to have a significant impact on world oil supply. For example the Bemolanga oil sands in Madagascar could produce 200 kb/d, with mining technology, at an oil price above $80 per barrel, according to the operator, Total.

Russia is thought to have several hundred billion barrels of technically recoverable extra-heavy oil and bitumen. The large bitumen resources thought to be present in Eastern Siberia are poorly known and difficult to exploit, due to their remoteness from infrastructure. Some of the reported heavy oil is, in fact, medium-viscosity and is exploited by conventional methods. In the more viscous reservoirs, and some of the bitumen deposits in Tatarstan, there have been pilot projects with steam stimulation, more recently with SAGD technology, but no clear plan exists for large scale development. Current economics favour the exploitation of large conventional oil resources. A similar situation exists in Kazakhstan. The Tatarstan Republic region of Russia, which is thought to have more than 20 billion barrels of extra-heavy oil and bitumen ultimately recoverable resources and an economy highly dependent on very depleted conventional fields, is the most likely location for the start of larger scale development. China has some heavy and extra-heavy oil reservoirs which are yet to be tapped, with probably a total of a few billion barrels of recoverable oil. The projections for these other countries are included in the conventional oil projections in this Outlook, as there is a continuum and no clear boundary between the categories (Figure 4.5). Only Canadian oil sands and Venezuela Orinoco extra-heavy oil have been separated out as unconventional oil on the basis of the very large resources involved. 164

Note: The size of the bubbles indicates recoverable resources. Reservoirs with similar properties in each geographical area have been grouped; the smallest bubbles each represent approximately 1 billion barrels of recoverable resources.

Oil shales Oil shales are fine sediments containing kerogen (Box 4.3). Because they are the source rocks for most conventional oil reservoirs, they are found in every oil province in the world. However, most of them are too deep to be exploited economically, as exploitation involves heating up the kerogen to temperatures between 350°C and 450°C in order to transform it into oil. So oil shales are generally considered possible sources of (unconventional) oil only when they are at shallow depth, though there can be exceptions, such as the Bazhenov shale in Russia (Box 4.4). The term shale oil is used to designate oil that has been produced through “retorting”, i.e. industrially heating up oil shales, whether done in-situ or after mining the shale rock.

There may be the equivalent of more than 5 trillion barrels of oil in place in oil shales around the world (including deeper shales) of which more than 1 trillion barrels may be technically recoverable (Table 4.6 includes only oil shales at shallow depth). How much may be economically recoverable is not known. The Green River area in the United States where Colorado, Utah and Wyoming meet is thought to contain more than half of all the recoverable oil shale resources in the world, around 800 billion barrels, and therefore has received the most attention. Oil shales have been exploited for centuries, mostly as a low-quality fuel for heating. Estonia has long mined oil shales for power generation. Worldwide, only a small amount (15 kb/d) is processed into liquid oil, in Estonia (4 kb/d), Brazil (4 kb/d) and China’s Fushun shale oil plant (7 kb/d). Extensive studies were made of the US Green River area and some pilot projects launched in the 1970s and 1980s, when this resource was seen as a potentially important source of domestic oil supply. However, during the period of low oil prices from the early 1980s to the early 2000s, all projects were shelved; only in the last few years have some feasibility studies and pilot projects been resumed. Australia Chapter 4 - The outlook for unconventional oil

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had a significant project planned in the Stuart shale near Gladstone in Queensland (up to 200 kb/d in the third phase) in the early 2000s, following a pilot plant in the 1990s, but it was shelved due to concerns about damage to the environment and rising costs. Box 4.3 z When oil from shales is not shale oil: the case of the Bakken The term, oil shales, is used to designate very fine grained sediments with a high content of kerogen, be they clays, marls or carbonates. However, such rock formations sometimes also contain oil. This can happen when at least part of the oil produced by the natural maturation of kerogen under deep burial has not been expelled to higher permeability sedimentary rocks, or when the shale, normally very impermeable, is fractured and can itself serve as an oil reservoir. When this is the case, oil shales can produce oil in exactly the same way as conventional, low permeability, fractured reservoirs. This is the case, for example, in the Bakken Shale in Montana and North Dakota in the United States and Saskatchewan in Canada. For the purpose of this report, such reservoirs are classified as conventional. They tend to be relatively localised and have steep decline rates, but they can contain significant resources: the Bakken, for example, contains 4 billion barrels of technically recoverable oil. Gas shales are analogues of such reservoirs, containing gas rather than oil. The recent “shale-gas revolution” in the United States has shown that such gas shales are quite common and can be economically exploited. This has triggered renewed interest in exploring oil shales for oil (rather than for their kerogen). Occidental Petroleum, for example, recently announced the acquisition of very large oil-shale acreage in California for the purpose of looking for oil-bearing shales similar to the Bakken. The Eagle Ford shale in Texas is also experiencing a boom in exploration for oil. The term “light tight oil” is emerging to describe these types of resources.

* A recent Chinese study from Jilin University, performed as part of the Chinese National Petroleum Assessment, reports 350 billion barrels in place of which 80 billion is recoverable. Sources: BGR (2009); Dyni (2005); USGS (2009b); USGS (2010).

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Production methods Oil-shale deposits near the surface can be mined, in a very similar way to mining in the oil sands: the “ore” (kerogen-rich shale) is then heated in industrial retorts, where the kerogen is transformed into oil and gas. The left-over shale is disposed of or used for land reclamation. Like all strip-mining techniques, land use is controversial, but the yield in barrels per acre can be about 10 times bigger than in Canadian oil sands mining, so the area of land disturbed will be less for a given level of production. This is primarily because deposits are thicker (which of course also results in deeper land disturbance, with possibly more impact on ground water). Somewhat deeper deposits, typically at depths from about 100 to 700 metres in the Green River area in the United States, require in-situ retorting or underground mining. Various technologies are being investigated for in-situ retorting, using very dense well networks (typically one well every few metres), with some wells used for heating with steam or electrical power and others for producing the oil and gas. Ten pilot projects are under investigation in this area (Table 4.7).

Table 4.7 z Proposed pilot shale-oil projects in the Green River area in the United States Companies/projects

Basin

Partners

Shell/Mahogany (4 projects)

Piceance

none

Chevron

Piceance

none

EGL

Piceance

none

AMSO

Piceance

Total (50%)

Uintah

Mitsui/Petrobras

Enshale

Uintah

Bullion Monarch Mining (parent)

Red Leaf/Ecoshale

Uintah

none

OSEC/White river mine

In addition to the United States, there are pilot projects planned in Canada and Jordan. The Jordanian project, led by the Estonian company Eesti Energia, aims for a capacity of 38 kb/d in 2017. Plans in China include expansion of the existing Fushun plant to 15 kb/d and several small (3 to 5 kb/d) pilot mining projects in other provinces. A joint venture with Shell has been announced, an in-situ pilot using the technology developed by Shell in its Green River property in the United States, though no date nor capacity have been reported.

Environment There have been fewer studies about the environmental issues associated with oil shales than those about Canadian oil sands. Yet the challenges are likely to be very similar. Retorting, whether done at the surface or done in-situ, requires large amounts Chapter 4 - The outlook for unconventional oil

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4

of energy to heat the oil shales to the required temperature of 350°C to 450°C. The energy required typically represents about 20% to 25% of the heating value of the produced oil in mining and surface retorting production methods and for in-situ projects it could reach 50%, though there are very few published analyses (Brandt, 2008). Most of this energy, however, can be provided by burning the oil shale itself in a surface retort, or producing gas in in-situ retorting that is then re-used to provide the energy. As a result of the large energy needs of shale oil production, CO2 emissions are also very large, unless the energy can be provided by renewable sources or the CO2 can be captured and stored. Estimates run from 180 to 250 kg CO2-eq/barrel of produced crude (Brandt, 2008). Development of oil shales is still in its infancy from a technological point of view, so some reductions can be expected in the future. However, the very nature of the process is likely to leave a differential with conventional oil of the order of 150 kg CO2-eq/barrel. At a price of CO2 of $50/ tonne, as in the New Policies Scenario in 2035, this represents $7.50/barrel, which significantly increases the required break-even oil price for these resources. CCS is probably the best option for mitigating these large emissions. The CO2 sources would be localised, so capture should be possible; and CO2 enhanced oil recovery in the Rocky Mountains area could provide a natural market for the CO2 from Green River shale projects. The rate of water use during retorting is estimated at two barrels of water per barrel of oil produced. Some recycling is probably possible, though the technology has not yet been deployed. The availability of water to sustain large scale production is likely to be a constraint in the Green River area, a relatively dry environment. Concern over pollution of surface and underground water is even greater than for Canadian oil sands, as the Green River deposits are much thicker than the oilsands deposits. Shell has worked on a “freeze-wall” technique, in which the water table is fully isolated from the shale submitted to in-situ retorting by a frozen wall surrounding the entire volume of shale. But this type of technology is still in its infancy and it remains to be seen whether it can achieve the objective of full isolation.

Land use for shale mining should be less than that involved in exploiting the Canadian oil sands, because of the higher hydrocarbon content per acre due to the thick layer of kerogen-rich shales in the Green River area. But the need for proper land reclamation will be just as strong. In-situ production may have similar land disturbance effects to in-situ projects in Canadian oil sands, the large number of wells required for heating the shale formation offsetting any benefit from the greater concentration of resources. Large-scale development of the Green River deposits in the United States is likely to face strong opposition on environmental grounds.

Costs and production prospects Cost estimates based on the various pilot projects in the pipeline in the United States indicate that oil shales investment and operating costs should be similar to, 168

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and possibly even slightly lower than, those of Canadian oil sands, with commercial exploitation possible at oil prices of the order of $60 per barrel at current costs. Adding a CO2 penalty corresponding to 150 kg CO2/barrel (compared to conventional oil) and taking into account the likely link between costs and the oil price (Biglarbigi, 2009) makes oil shale exploitation economic in both the Current Policies and New Policies Scenarios, though this is the most costly of our unconventional fuel sources, together with CTL. In the 450 Scenario, the lower oil prices and higher prices of CO2 make oil shales marginal from an economic point of view. Costs in China have been reported to be much lower — less than $25 per barrel (Qian, 2008) — but there is no recent confirmation of this figure. There is long way to go from pilot projects producing a few thousand b/d to an industrial scale activity able to produce quantities that are significant in terms of world oil supply. For example Shell has indicated it will not take a decision on a commercial scale project in the Green River area before 2015 and such a project would then probably take 10 years to reach large scale operation, say in excess of 100 kb/d. These long time scales, together with the small number of projects being piloted, explain why we foresee only slow growth of oil shale exploitation even in the New Policies Scenario; oil shales begin to play a small role only at the end of the projection period (Figure 4.6).

mb/d

Figure 4.6 z Shale-oil production by country in the New Policies Scenario 0.4

Faster exploitation of oil shales in the United States could result from strong government policies, motivated by energy security. However, even a massive government programme is unlikely to lift production above 1 mb/d by 2035, still amounting to only a fraction of projected US imports of close to 8 mb/d. China could see faster development of its oil-shale industry, but currently planned projects are all on a small scale, suggesting that slow growth is likely there as well. Chapter 4 - The outlook for unconventional oil

Oil shales are generally considered of interest only when they are at shallow depths. Most analyses of resources contained in oil shales include only such shallow deposits. Deeper source rocks, even if they contain a very large amount of kerogen, are generally not considered exploitable economically. However there are still places where they could play a significant role. An example is the Bazhenov shale in western Siberia. The Bazhenov is the source rock for all the oil fields of western Siberia. It underlies the entire western Siberia basin, an area of about 1 million km2. It is estimated to contain kerogen corresponding to 1 trillion barrels of oil. However it lies at depths from 2 500 to 3 000 metres, too deep for mining, but also too deep to be economically recoverable with the in-situ recovery techniques being developed in the US Green River area. But Russia has a unique geography: most of its oil and gas resources lie in remote regions, scarcely populated and with a harsh climate. Development of such resources requires large investments in infrastructure, such as housing, roads, air strips, water supplies and energy supplies. In western Siberia, such infrastructure was developed in the 1970s and 1980s, at the time when the Soviet Union began to develop the western Siberian oil fields. The conventional exploitation of the basin is now mature and decline will soon set-in. To maintain its oil production, Russia has started to explore and develop the huge area of eastern Siberia. However this is an even more remote province, which will require very large investment in infrastructure to build up significant production. As a result there is considerable interest in developing technology in western Siberia that would allow exploitation of the Bazhenov oil shale formation, which would make use of the existing infrastructure and extend the life of the basin as a producing area. So how could it be done? Probably the most promising approach involves in-situ combustion, similar to the THAI or COGD technologies being piloted in the Canadian oil sands (see the oil sand section earlier in this chapter). How well such technology could work in oil shales is unknown at this time, but pilot projects are likely to be undertaken in the next few years. However, even if they are successful, large-scale implementation is probably a couple of decades away, allowing for the time necessary to build-up experience from small-scale pilots and then scaling-up the process. Some parts of the Bazhenov formation are fractured and contain oil in addition to kerogen, like the Bakken shale in the United States. These localised reservoirs are likely to be exploited earlier, with Bakken-shale-like horizontal wells, prolonging the life of some of the oil towns of western Siberia.

Coal-to-liquids Although economical at assumed oil prices in each of the three WEO scenarios, oil derived from coal-to-liquids processes (CTL) and oil shales is the most expensive of the unconventional oil sources. Provided carbon capture and storage (CCS) is accepted 170

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(both by regulators and by public opinion), CTL is likely to develop faster than oil shales because the technology is more mature and less risky and the environmental impact is less controversial: the plants will mostly be located near active coal mines that are already being exploited, so land use is likely to be more acceptable to the local communities. Coal-and-biomass-to-liquids (CBTL) with CCS, with its smaller carbon footprint, is particularly attractive. Taking into account the current slow build-up of announced projects, the time it takes to approve large investments and the time required to build large scale plants, most of the growth in CTL in the New Policies Scenario will take place in the second half of the projection period (Figure 4.7). The Current Policies Scenario, which assumes higher oil prices, sees faster growth (Table 4.1). The 450 Scenario follows a trajectory very similar to that of the New Policies Scenario: although oil demand is weaker, demand for coal is even more reduced, making the price differential between oil and coal larger and therefore making it more economically attractive to build CTL plants; in addition, acceptance of CCS is assumed to be faster.

mb/d

Figure 4.7 z Coal-to-liquids production by country in the New Policies Scenario 1.2

CTL, a process involving synthesising liquid hydrocarbons from coal, has a long history. First used industrially in Germany during the Second World War, it was then extensively applied in South Africa. Sasol started its famous CTL plant there in 1955 and has since produced more than 1.5 billion barrels of synthetic liquid fuel. There are several routes to turn coal into liquid hydrocarbons. The most popular starts with gasification of the coal to turn it into “syngas”, a mixture of hydrogen and carbon monoxide. This is similar to the old “town gas” that was used before natural gas became widely available. The same process of gasification is used in integrated gasification combined-cycle (IGCC) power plants. In a second step, the syngas is turned into a liquid Chapter 4 - The outlook for unconventional oil

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hydrocarbon, typically high quality diesel, using the Fischer-Tropsch catalysis technique with an iron or cobalt catalyser. This was the technology used in Germany during the Second World War and it is still used by Sasol in its 160 kb/d capacity plant in South Africa. An alternative to the second step is to first turn the syngas into methanol and then the methanol into gasoline. This process was piloted by ExxonMobil; a plant operated in New Zealand for ten years before closing. Methanol can also be converted to DME (dimethyl ether), which is being commercialised in Asia as a liquified petroleum gas (LPG) blend stock and being developed as a diesel alternative, or used as petrochemical feedstock as in the Baotou plant of the Shenhua coal company in China. Finally there is the “direct” route, in which the coal is directly reacted with hydrogen, in the presence of suitable catalysers, to produce liquid oil that can be used in a standard refinery to produce commercial hydrocarbon products. This is the technology used by the Shenhua coal company in China in its plant in Inner Mongolia. The plant has a nameplate capacity of 24 kb/d, but is still in the start-up phase. Similar technology was also used in Germany during the Second World War. Most projects under study plan to use one of the two indirect routes, since the technology is more mature. Even though no new plant has been built recently, there is considerable experience with the key components (gasification and Fischer-Tropsch) in other applications (power generation, GTL, chemical plants). It also provides more flexibility: syngas can be used for power generation, as chemical feedstock and to produce methane, in addition to being used as an input to the second stage of liquid hydrocarbon synthesis. As the gasification unit represents the largest capital investment, this offers a useful diversification of the investment risks. There is also some flexibility in the feedstock to the gasification process: biomass can be mixed with the coal in CBTL (coal and biomass-to-liquids), or even used by itself (BTL, biomass-toliquids), without major changes to the equipment.

Projects and economics A number of projects have been announced in the past five years, some ten in the United States, half a dozen in China, a few in Indonesia, India and Australia, one in Canada and a second plant in South Africa. However many of them are in a very early pre-feasibility phase and little information is available about plant capacity and timing. Several have also been put on hold, due to uncertainty about oil prices and CO2 costs. Several projects announced the intended use of CBTL. The most advanced seem to be:  The Clinton project in Australia, with a capacity of 13 kb/d scheduled for 2015.  The Felton/Ambre project in Australia, with a capacity of 18 kb/d, scheduled for

2014, based on the ExxonMobil methanol-to-gasoline process.  The DKRW Medicine Bow project in the United States, with a capacity of 20 kb/d

expected in 2015, also based on the Exxon-Mobil process.  The Rentech Natchez project in the United States, with a capacity of 30 kb/d. 172

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 Three 4-kb/d projects in China, in Lu’An and Yitai with the Fischer-Tropsch route

and the ExxonMobil-Jincheng Anthracite Mining Co (JAMG) project using the methanol-to-gasoline route. These are all in the start-up phase. The largest projects are those being investigated by Sasol, one with a possible site in China, one in India, one in Indonesia and a second site in South Africa. Each would have 80 kb/d capacity. No dates for construction or operation have been announced. Assuming four to five years for the feasibility study and design, followed by five years for construction and start-up, these plants could come on stream around 2020. Monash Energy (a Shell/Anglo-American joint venture) has announced a 60 kb/d capacity project in Australia, with start of construction possible by 2015. Russia is considering a large project in collaboration with the Chinese coal company Shenhua. Essentially, all of the announced projects assume capture and storage of CO2 emissions (more on this below). Uncertainty surrounding the regulatory framework for CCS is probably one of the key reasons for the slow pace of development of new projects. The Linc Energy Chinchilla project in Australia is also worth mentioning. It combines Underground Coal Gasification (UCG) to produce the syngas, with a Fischer-Tropsch plant to transform the syngas into liquid hydrocarbon. The project aims at a capacity of 20 kb/d of liquid hydrocarbons. In principle, UCG provides the syngas at much lower capital costs and allows deeper, un-mineable, coal beds to be exploited. UCG has been piloted in various places in the world, with mixed success; although in principle very attractive, it is considered an immature technology (see Box 6.1 in Chapter 6). Because no large plant has been built recently, there is a range of estimates for the capital costs associated with CTL technology: capital costs range from $80 000 to $120 000 per b/d of capacity. Syngas/FT plants offer significant economies of scale and are in this range of capital costs only for capacities above 50 kb/d. The capital costs of plants using the methanol and direct routes are less dependent on size. The equivalent oil price required to make CTL economical is in the range $60 to $100/barrel, depending on the location of the projects (China being in the lower part of the range) and the cost and quality of the feedstock. These prices include CCS, which typically represents only a small addition to the cost, as explained below. CTL is economical at the assumed oil price trajectories in all three scenarios even though, together with oil shales, it constitutes the most expensive source of unconventional oil in our models.

Environment CO2 emissions are the main disadvantage of CTL. These emissions are different from those of a coal-based power plant. Basically, to turn coal into diesel or gasoline means adding hydrogen and making it react with the coal to form hydrocarbon chains. The CO2 emissions arise primarily from generating the hydrogen. In the direct CTL approach, it is in principle possible to generate the hydrogen using renewable energies, although this may be expensive. Chapter 4 - The outlook for unconventional oil

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In the indirect routes, it is intrinsic to the syngas generation process that the energy comes from the coal itself. CO2 is produced with the syngas. However it must be separated from the syngas prior to the Fischer-Tropsch (or methanol) process. So the bulk of the CO2 is, in any case, captured. This is why CCS is a relatively inexpensive addition: only transport and storage need to be added, and these are normally much less expensive than capture. Estimates for the cost of adding CO2 purification to a CTL plant, as required for sequestration, range from $3 to $5/barrel of oil produced. Various studies have shown that, without CCS (or with conventional hydrogen production for the direct CTL route), the well-to-wheels emissions of CTL are 80% to 100% higher than those of conventional oil. This is why most proposed projects include CCS from the start. With CCS, a CTL plant can produce diesel with well-to-wheels emissions 5 to 10% lower than conventional oil (as production and refinery emissions are not captured for conventional oil). Adding from 10% to 30% of biomass to the coal feedstock (CBTL) can make well-to-wheels emissions 20% lower than those of conventional oil (US DOE, 2009b), with only moderate impact on the economics. This is why several of the announced projects plan to use CBTL. Water usage in existing plants is reported to be quite significant: more than 10 barrels of water per barrel of oil produced. At this level, water availability could be a constraint on the location of CTL plants. The quality of used water released back to the environment also needs to be carefully monitored. However, most of the water can in principle be recycled and it should be possible to restrict actual use of water to less than two barrels per barrel of oil produced. Coal mining itself uses water, with one barrel of water per tonne of coal being typical. A typical CTL plant would produce 2 to 3 barrels of liquid hydrocarbon per tonne of coal. It is expected that the mines feeding the CTL plants would also be used to provide coal for power generation, so the actual increase in water usage would depend on what fraction of the mined coal is used in the CTL plants.

Gas-to-liquids Gas-to-liquids (GTL) is a relatively mature technology, but experienced an upsurge in interest in the early to mid-2000s as a result of technological advances and higher oil prices. However, some technical problems with the commissioning of a new plant in Qatar and a sharp rise in construction costs, together with increased interest in LNG, which competes with GTL for gas feedstock, have led to many planned GTL projects being shelved in the last few years. Some projects are, nonetheless, under construction and we assume that several others, now at the planning stage, will also be commissioned. The current low price of gas and the persistent large price differential between gas and oil prices that we assume in our projections could lead to a resurgence of interest in GTL, with producers diversifying their portfolios with more ways of monetising gas in order to mitigate the risks of price fluctuations. However, the lengthy time scales involved in design, approval, construction and start-up of new large plants are likely to lead to slow growth in production. In the New Policies Scenario, GTL production rises from about 50 kb/d in 2009 to almost 200 kb/d in 2015 and to nearly 750 kb/d in 2035 (Figure 4.8). 174

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mb/d

Figure 4.8 z Gas-to-liquids production by source in the New Policies Scenario 0.8

Small-scale Other large-scale Algeria

0.6

Nigeria Qatar

0.4

4

0.2

0

2000

2009

2015

2020

2025

2030

2035

Note: Production is assumed to average 80% of installed capacity.

Gas-to-liquids (GTL) technology is similar to the CTL indirect route: natural gas (primarily methane) is reacted with steam and oxygen to form syngas (a mixture of carbon monoxide and hydrogen) and, in a second step, the syngas is turned into liquid hydrocarbon using the Fischer-Tropsch synthesis, typically yielding high-quality diesel and naphtha. The technology has a long history, dating back to the Second World War. Just as with CTL, it is possible to turn the syngas into methanol and then the methanol into gasoline, using the ExxonMobil process. Methanol can also be converted to DME (dimethyl ether) which is being developed as a diesel alternative, due to its high quality and clean burning characteristics.

Currently, GTL plants are economical only on a large scale, due to economies of scale. With capital costs of $60 000 to $100 000 per b/d of capacity and low operating costs, large-scale GTL projects (30 kb/d and above) are estimated to be economical at crude oil prices as low as $50 to $70/barrel.8 However many efforts are being made around the world to design GTL processes that would be economical at smaller scales. The prize is enormous as small scale GTL (or, for that matter, economical small-scale LNG) would make it possible to produce the enormous amount of “stranded gas” (known gas fields that have no economical way to bring the gas to market) or to avoid flaring the associated gas produced with oil in places where there is no way to transport the gas economically. It is estimated that about 140 billion cubic meters of gas are flared every year, about one third of the gas consumption of Europe and 5% of world-wide gas production. Turning just the flared gas into liquids would produce as much liquid fuel as 1.4 mb/d of crude. Several pilot facilities with new micro-channel technologies are being built, for example by CompactGTL or by Velocys for Petrobras. Such technologies are expected to be deployed in significant numbers in the 2020s and applications to grow rapidly in the 2030s, driven in part by efforts to eliminate flaring completely.

8. The lower part of the range may apply to wet gas (gas rich in NGLs) for which the NGLs provide additional revenue.

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175

Two projects have been producing for many years: the Sasol 25 kb/d Mossgas facility in South Africa and the Shell 15 kb/d Bintulu facility in Malaysia. In the early 2000s, Qatar proposed a large number of GTL projects (totalling as much as 700 kb/d) to commercialise gas from its giant North field. However, many of these proposed projects were shelved after Qatar declared a moratorium on GTL in 2006. Only one new project has been built, the Oryx 30 kb/d plant, which started operation in 2007 and has now reached its nameplate capacity. The Shell 140 kb/d Pearl project is under construction, with first production expected in 2011. Other large projects are the Escravos 33 kb/d plant in Nigeria, currently under construction and expected to start production in 2013, and the recently announced Sasol project in Uzbekistan, with a 35 kb/d capacity and no target completion date yet announced (it is assumed to be commissioned before 2020 in the New Policies Scenario). Several other proposed projects, such as the Sonatrach Tinrhert project in Algeria and the Ivanhoe project in Egypt have been shelved, though the growing disconnect between gas and oil prices could lead to their revival in the future. Interest in GTL has been expressed in Russia, as a hedge against low gas prices, and in Turkmenistan, to help the country diversify its market outlets. Although it tends to benefit from the positive image of gas as a greener hydrocarbon, the CO2 footprint of GTL is not small. In modern plants, about a quarter of the carbon content of the natural gas is turned into CO2 during the synthesis process. As a result, the well-to-wheels CO2 emissions of GTL diesel are about 10% higher than those of diesel refined from conventional crude (just as for oil sands, this has to be qualified: some conventional crudes also have higher emissions than average and their emissions can be higher than GTL). A number of technical solutions exist, either involving storage (completing the CCS process) of the fairly concentrated CO2 stream coming out of the process, or improved reforming processes that can recycle a large part of the CO2. Future plants are likely to apply some of these technologies and achieve a CO2 footprint similar to or better than that of conventional oil. Water usage is not a serious issue for GTL, with the newer plants (e.g. the Pearl project in Qatar) planning to recycle close to 100% of the water required in the process. Similarly, the physical size of the plant is similar to that of a refinery of equivalent capacity and does not give rise to specific land usage issues.

Additives A variety of chemicals are added to crude oil as it enters refineries, or are blended into finished products. For example, anti-knocking agents, such as methyl tertiary butyl ether (MTBE), ethyl tertiary butyl ether (ETBE), or tertiary amyl methyl ether (TAME), are added to gasoline and methanol or ethanol can be blended with gasoline. Such chemicals are produced by the petrochemical industry from varying original feedstocks: oil, natural gas, coal and biomass. Since they contribute to both the volume and energy content of oil products, these additives must be accounted for in the balance between demand and supply. The part that originates from natural gas or coal is, quite reasonably, usually reported as unconventional oil, as they can be classified 176

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as a variation on GTL or CTL. However, it is not easy to separate the contributions of gas and coal from the other feedstocks. As an example, MTBE is obtained from reacting methanol with iso-butene. The methanol is generally obtained from gas or coal (although bio-methanol is now coming onto the market), but the iso-butene can be made by a variety of different routes from varying feedstocks, such as gas, NGLs and oil-refinery products. Similarly, ETBE can be made from petrochemicals or from bio-ethanol. In the United States, MTBE usage has essentially been eliminated, being replaced by bio-ethanol. In Europe, a mix of MTBE and ETBE (coming from bio-ethanol) is used; MTBE is expected to continue to make up between 30% and 50% of these fuel ethers, as a compromise between cost and biofuel content. MTBE consumption is growing in the rest of the world. Blending of methanol in gasoline is rapidly growing, particularly in China, where a 15% methanol mix (M-15) is common and M-85 (85% methanol) is being introduced. This requires engine modifications that have been agreed between car manufacturers and the Chinese government. DME (dimethyl ether, a compound obtained from methanol) usage as an LPG blendstock is growing rapidly in a number of countries. Methanol is also used as a trans-esterification agent in the manufacture of biodiesel; one tonne of biodiesel incorporates about 0.1 tonne of methanol. With at least part of this methanol coming from gas or coal feedstock, the growing use of biofuels will create an increase in this “unconventional oil” supply.

With the expected decrease in oil demand in OECD countries and growth in demand in emerging economies, our projections (Table 4.1) show an increase in additives as a percentage of total oil supply in both the New Policies and the Current Policies Scenarios. In the 450 Scenario, the large reduction in overall demand for gasoline offsets the percentage growth in content of additives to result in a stable supply of additives. The supply of additives is reported as “oil equivalent” barrels, as the additives have lower energy content per barrel than oil (for example, less than half for methanol, about 60% for DME and about 75% for MTBE).

z Global natural gas demand is set to resume its long-term upward trajectory from

2010, following an estimated 2% drop in demand in 2009 — the biggest since the 1970s. It is the only fossil fuel for which demand is higher in 2035 than in 2008 in all scenarios, though it grows at markedly different rates. In the New Policies Scenario, demand reaches 4.5 tcm in 2035, an increase of 1.4 tcm, or 44%, over 2008 at an average rate of increase of 1.4% per year. Demand grows more quickly, by 1.6% per year, in the Current Policies Scenario; in the 450 Scenario, demand rises by a more modest 0.5% per year, peaking in the late 2020s. z In the New Policies Scenario, non-OECD countries account for 84% of the increase

in demand between 2008 and 2035. China’s demand grows fastest, at an average rate of almost 6% per year, and the most in volume terms, accounting for almost a quarter of the rise in global demand to 2035. Demand in the Middle East, which is well-endowed with relatively low-cost resources, increases almost as much. z In that scenario, the Middle East also leads the expansion of gas production

over the Outlook period, its output almost doubling to 800 bcm by 2035. Twothirds of this increase is consumed locally. China sees a sizeable expansion of capacity too, with most of the increase in the longer term coming from tight gas deposits, coalbed methane and shale gas. Around 35% of the global increase in gas production in this scenario comes from such unconventional sources. z International trade in natural gas is set to grow. In the New Policies Scenario, gas

trade between all WEO regions expands by around 80%, from 670 bcm in 2008 to 1 190 bcm in 2035. China’s imports grow the most, from just 5 bcm in 2008 to 200 bcm in 2035. In fact, China accounts for a stunning 40% of the growth in interregional trade over the Outlook period. Most of the growth in gas trade takes the form of LNG; LNG trade doubles between 2008 and 2035. LNG supply will expand rapidly in the next few years as a wave of projects are completed.

z A sizeable glut of global gas-supply capacity has developed, a result of the

economic crisis, which depressed gas demand, together with unexpectedly strong growth in unconventional gas production in the United States in the last few years and a surge in LNG capacity. Based on projected demand in the New Policies Scenario, we estimate that the glut, measured by the difference between the volumes actually traded and total capacity of inter-regional pipelines and LNG export plants, is set to reach over 200 bcm in 2011, before starting a hesitant decline. This glut will keep the pressure on gas exporters to move away from oilprice indexation.

Chapter 5 16- Natural - Asean-4gas country marketprofiles outlook

179

Demand Primary gas demand trends To say that natural gas is entering a golden age may be an exaggeration, but it is certainly set to play a central role in meeting the world’s energy needs for at least the next two-and-a-half decades. Global natural gas demand grows across the three scenarios, especially after 2015, though the rates of growth are markedly different, reflecting the differing impact of government energy and environmental policies. Nonetheless, demand is significantly higher in 2035 than in 2008 in each scenario (Figure 5.1). In the New Policies Scenario, demand growth slows progressively over the Outlook period, total demand reaching 4.5 trillion cubic metres (tcm) in 2035 (Table 5.1) — an increase of 1.4 tcm, or 44%, over 2008 and an average rate of increase of 1.4% per year. Demand grows more quickly — by 1.6% per year — in the Current Policies Scenario, attaining 4.9 tcm by 2035, with only a modest slowdown in the rate of demand growth towards the end of the projection period. In the 450 Scenario, gas demand peaks towards the end of the 2020s and then begins to decline, reaching 3.6 tcm in 2035 — a 15% increase over 2008 but about 5% down on its peak. In fact, gas is the only fossil fuel for which demand is higher in 2035 than in 2008 in this scenario. The share of gas in overall primary energy demand worldwide rises marginally over the projection period in the Current and New Policies Scenarios, but falls slightly after 2025 in the 450 Scenario, as the market penetration of renewables and nuclear power increases.

There is only a modest difference in gas demand growth rates across the three scenarios in the period to 2015, with global demand in every case recovering steadily following a drop in demand in 2009 — the biggest since the 1970s. According to preliminary data, demand in 2009 plunged by around 2% as a result of the global economic crisis, the decline occurring mainly in the OECD (averaging more than 3%). Trends diverged more in non-OECD countries, with demand plummeting in Russia, but continuing to grow strongly in China, India and the Middle East. In the OECD and Russia, demand 180

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was affected most by falling industrial output, which reduced gas needs for heat and process energy, and falling demand for electricity, which reduced gas needs for power generation. However, power sector gas demand did not fall, or at least not much, in all OECD countries: gas managed to increase its share of the power generation mix in some cases, notably the United States, usually because of competitive pricing. Table 5.1 z Primary natural gas demand by region and scenario (bcm) New Policies Scenario OECD Non-OECD World Share of non-OECD

Current Policies Scenario

450 Scenario

5

1980

2008

2020

2035

2020

2035

2020

2035

958

1 541

1 625

1 758

1 637

1 840

1 528

1 330

559

1 608

2 169

2 777

2 198

3 047

2 055

2 279

1 517

3 149

3 794

4 535

3 835

4 888

3 584

3 609

37%

51%

57%

61%

57%

62%

57%

63%

There are signs that gas demand is already starting to rebound, with OECD demand in the first quarter of 2010 up by an estimated 7% on the same quarter a year earlier (though demand was boosted by exceptionally cold weather). Demand rose by an estimated 5% in the second quarter. Over the whole of 2010, demand worldwide is expected to climb by more than 2%, though this will depend on near-term economic prospects as well as gas pricing, which can have a major impact on demand for gas in the power sector. For example, gas use for power generation actually increased by 4% in 2009 in the United States, because gas was more competitive than coal in some locations (IEA, 2010). On the assumption that the global economic recovery continues (see Chapter 1), demand is projected to resume its long-term upward path. It grows by 12% between 2008 and 2015 in the New Policies Scenario (compared with 13% in the Current Policies Scenario and 10% in the 450 Scenario).

Regional trends Non-OECD countries will continue to drive gas demand growth over the next quarter of a century. In the New Policies Scenario, they account for 84% of the increase in demand between 2008 and 2035 (Table 5.2). China’s demand grows faster than in any other region, at an average of almost 6% per year in 2008-2035, and the most in volume terms, reaching nearly 400 billion cubic metres (bcm) per year by the end of the Outlook period. China accounts for 22% of the increase in global demand over the projection period. Projected growth in the medium term is spectacular, with demand jumping from around 85 bcm in 2008 (and an estimated 98 bcm in 2009, based on preliminary data) to almost 170 bcm in 2015 and 215 bcm in 2020, the result mainly of booming demand in the power, residential and industrial sectors. In the longer term, gas demand is driven increasingly by the power sector, which accounts for almost half of total gas use in China in 2035. Yet gas still accounts for only 8% of all inputs to power generation by 2035 and the share of gas in China’s overall primary energy mix reaches Chapter 5 - Natural gas market outlook

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only 6% in 2020 and 9% in 2035, compared with 3% in 2008. By 2035, China’s gas market is still 20% smaller than that of Russia and 40% smaller than that of the United States — the world’s largest. Table 5.2 z Primary natural gas demand by region in the New Policies Scenario (bcm) 1980

The Middle East, which is well-endowed with large and relatively low-cost resources, sees an increase in gas demand almost as big as that of China in absolute terms. This is driven by rising needs for power generation (the result of rapid growth in electricity demand and policies to replace oil with gas to free up more oil for export) and by use in heavy industry and as a feedstock for petrochemicals. Demand in non-OECD Asia and Latin America also grows rapidly. India’s demand grows almost as fast as China’s, at 5.4% per year, but reaches only about 180 bcm by the end of the Outlook period, as it starts from a lower level (demand barely exceeded 40 bcm in 2008). Nonetheless, India’s gas market would still be bigger than that of any OECD country except the United States. Increased availability of gas 182

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from the Krishna Godavari field, which came into production in 2009, is set to fuel an expansion of demand to more than 60 bcm in the very near future. Other developing Asian countries also see rapid growth. Among the non-OECD regions, demand in Russia grows least rapidly, by only 11% between 2008 and 2035, mainly because of continuing improvements in energy efficiency (as out-of-date technologies are replaced) and less waste — in part the consequence of higher prices as subsidies are phased out. Demand in Caspian countries grows more quickly, by 50% between 2008 and 2035, mainly for power generation (see Chapter 16). Brazil’s demand grows strongly, tripling by 2035, drawing on the rapid development of the large offshore resources that have been discovered in the last few years. The prospects for demand in the mature OECD markets are generally much weaker, largely because economic growth — the main determinant of gas demand — is assumed to be lower than in the rest of the world. In addition, there is much less scope for increased residential demand in OECD countries, because of saturation effects (most homes that can economically be heated with gas already are, and the number and size of households will barely grow). Industrial demand actually falls marginally between 2008 and 2035 in the New Policies Scenario, as slow growth in industrial production is outweighed by improved end-use efficiency. Power-sector demand will also be constrained by the growth in renewables-based generating capacity, which is always given priority in dispatching power ahead of gas-fired plants (as renewables often have low or zero operating costs). In that scenario, total OECD gas demand grows by only 0.5% per year on average to 2035, with growth slowing progressively over the projection period as higher prices and policies to curb gas and electricity demand take effect. In the United States, gas use in total declined by an estimated 1.7% in 2009, but is projected to recover slowly to 2035, due to rising demand for power generation (which averages 0.4% per year); the share of gas in power output remains flat at about 20%.

The power sector is set to remain the leading contributor to gas-demand growth in most regions. Yet, just how fast gas-fired generation will grow in the coming decades is very uncertain for several reasons, including relative fuel prices, the capital costs of building different types of generating plant, the ease of financing new power plants, government policies on renewables and nuclear power, and environmental policies and measures to deal with emissions of pollutants and greenhouse gases, including plans for CO2-emissions trading. In the New Policies Scenario, power and heat generation account for more than 45% of the global increase in gas use between 2008 and 2035 (Figure 5.2). Gas-burning in power stations and heat plants (including co-generation plant) increases by more than half over that period — an average annual rate of growth of 1.6%. As a result, the power sector’s share of the world gas market increases marginally, from 39% in 2008 to 41% in 2035. Despite rising prices, natural gas used mainly in combined-cycle gas turbines (CCGTs) is expected to remain the preferred option for new power stations in many parts of the world, because of its inherent environmental advantages over coal (notably its Chapter 5 - Natural gas market outlook

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5

much lower carbon content and smaller contribution to local air pollution), the higher thermal efficiency and lower capital costs and construction lead-times of CCGTs, and their operational flexibility (see Chapter 7). The expansion of carbon trading and rising CO2 prices enhance the competitiveness of gas against coal in power generation, though renewables and nuclear power are favoured even more. For this reason, gas is often the lowest-cost generating option at CO2 prices that are neither very low nor very high: low prices typically favour coal, while high prices (for example, in excess of $100/tonne as assumed after 2030 in the 450 Scenario) favour renewables and nuclear power. Figure 5.2 z World primary natural gas demand by sector in the New Policies Scenario 2008 Power generation

Demand for gas in industry is set to grow faster than in any other end-use sector other than transport (where gas use remains small, globally). In the New Policies Scenario, industrial demand rises by 1.3% per year on average over the projection period, with most of the increase coming from non-OECD countries (mainly in Asia and the Middle East). Direct use of gas by industry in OECD countries barely grows, as industrial output expands only slowly, electricity accounts for much of the increase in industrial energy needs and efficiency gains limit the need to burn more gas. Worldwide, gas demand in other end-use sectors — mainly residential and services — grows by 1.1% per year. Growth in the use of gas in buildings — which remains the largest end-use sector — for space and water heating is limited by saturation effects in many OECD countries. In much of the rest of the world, the potential for using gas for space heating and hot water is generally lower, because of climatic factors and the high cost of building local distribution networks. Nonetheless, some countries see rapid growth in gas use in buildings. China is in the midst of one of the largest residential construction booms in history, with thousands of new housing estates being connected to local gas distribution grids every month, increasing demand massively and accounts for almost one-third of the global increase in gas use in buildings between 2008 and 2035. 184

Oil and gas prices: a temporary separation or a divorce? Spot gas prices weakened significantly in 2009 and the first half of 2010, relative to oil prices, reflecting two revolutions on the supply side: the surge in LNG capacity, which will see liquefaction capacity growing by 47% between end-2008 and end-2013, and the unexpected boom in unconventional gas production in North America. With demand for gas dropping heavily in the face of recession, a sizable glut of gas has emerged. Gas demand is expected to recover in 2010, but less rapidly than oil demand, which is being driven mainly by China and other large non-OECD economies that tend to be much less dependent on gas. The result of this gas-market imbalance is that a large and unprecedented gap has opened up between the prices prevailing in the competitive markets of North America and Great Britain, on the one hand, and those in continental Europe and Asia-Pacific, where gas prices remain largely indexed to oil prices under long-term contracts, on the other. In 2009, the spot price averaged $4 per million British thermal units (MBtu) at Henry Hub in the United States and $5/MBtu at the National Balancing Point in Britain, compared with around $9/MBtu in Japan and continental Europe. This regional gas price decoupling is already putting pressure on buyers of gas under oil-linked contracts in Europe to seek changes from their suppliers to their pricing terms — a development that we predicted in last year’s Outlook. Gas buyers are caught between their long-term contractual obligations and the pressure from their customers, in particular industrial, to supply gas at more competitive prices. Russia’s Gazprom has already granted some important concessions on pricing, partially moving from oil to spot gas price indexation over a three-year period, with prices falling as a result in key markets like Germany. This has led to a narrowing of the gap between spot and contract prices in Europe. Take-or-pay clauses have also been eased, giving more flexibility to buyers as to when they are required to lift contracted volumes. The 64-million-dollar question now is: what will happen to the traditional oil-gas price linkage on European continental and Asian markets? The suppliers claim that recent pricing concessions are merely temporary. Whether the use of spot gas price indexation remains beyond the three years, and is extended to other contracts, or traditional oil indexation fully returns will depend on the global supply/demand balance and on the evolution of the gap between the different spot and oil-linked prices. For as long as the gas glut persists — and our analysis suggests it will for several years (see below) — the pressure to move further away from oil indexation will remain, especially for new long-term contracts. Ultimately, full contractual decoupling between gas and oil prices could occur, were sufficient momentum to build, though the dynamics of interfuel competition are likely to ensure a continuing degree of correlation between fuel prices. Contractual price decoupling would not necessarily mean weaker gas prices in the longer term: as the gas glut gradually dissipates, gas prices are likely to come under renewed upward pressure relative to oil prices, with the rising cost of supplying gas from remote and difficult locations.

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5

Gas demand is set to expand rapidly in two emerging sectors: as feedstock for gas-toliquids (GTL) plants and as a road-transport fuel. At present, there are only three large GTL plants in operation worldwide, the biggest of which — the 34 thousand barrels per day (kb/d) Oryx plant in Qatar — was commissioned in 2006, though production only recently approached its full capacity (see Chapter 4). The other two are Shell’s 15-kb/d Bintulu plant in Malaysia and PetroSA’s 25-kb/d plant in South Africa. Two more plants are under construction: Shell’s 140-kb/d Pearl plant in Qatar, which is due to start operation in 2011, and the 34-kb/d Escravos plant in Nigeria being built by Chevron and the Nigerian National Oil Company, which is planned to start-up in 2012. By 2015, assuming there are no technical problems, all these plants together will consume around 20 bcm — up from 8 bcm in 2008 (when Oryx was still being commissioned) — and produce around 190 kb/d of liquids (mostly high-quality diesel and other light oil products). In the longer term, the prospects for GTL projects hinge particularly on relative oil and gas prices, and on the operational performance of the new plants. We assume that a project under development in Uzbekistan, together with some other projects in the Middle East and Africa, are completed, pushing up the volume of gas consumed in GTL production to 40 bcm (with oil production reaching 400 kb/d) by 2025 and 72 bcm (750 kb/d) by 2035. The recent fall in the price of gas relative to oil (see Spotlight below), especially in North America, has stimulated interest in using natural gas as a road-transport fuel. Today, natural gas vehicles are common in only a few countries and the global use of compressed natural gas (CNG) as a road fuel is tiny (see Chapter 3). The biggest potential lies with heavy-duty vehicles (trucks and buses), as the costs of installing refuelling infrastructure for light-duty vehicles and adapting cars to run on gas are likely to limit the growth of CNG use in light vehicles. There is scope for increased CNG consumption in countries with an established market, notably in non-OECD Asia and Latin America. But the potential may be greatest in North America, where abundant supplies of unconventional gas are expected to hold gas prices down in the coming years, making CNG an attractive alternative to diesel for heavy-duty vehicles. Nonetheless, the take-off of CNG use even there is likely to be slow, in view of the need to develop distribution facilities. In the New Policies Scenario, we project North American gas use for road transport to grow from 0.9 bcm in 2008 to 12 bcm by 2035, with global use rising from 18 bcm to 61 bcm over the same period.

Resources and reserves1 Remaining resources of natural gas are abundant, relative to those of oil, and are easily large enough to meet the projected increase in global demand — even in the Current Policies Scenario. The biggest uncertainty for supply over the next quarter 1. See Box 3.2 in Chapter 3 for our definitions of reserves and resources and WEO-2009 for a more detailed discussion of gas resources (IEA, 2009). 186

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of a century is whether sufficient and timely investment will be made in developing those resources and how much their exploitation will cost. Proven reserves of gas have increased steadily since the 1970s, as reserve additions have outpaced production by a wide margin. Proven reserves stood at 184 tcm at the end of 2008 — close to twice as high as 20 years ago and equivalent to 58 years of production at current rates and 42 years at our projected average annual growth rate of 1.3% in the New Policies Scenario.2 Most of these reserves are conventional gas; unconventional gas forms a significant proportion of the total only in the United States — the leading unconventional gas producer — and Canada. The overwhelming bulk of the world’s proven reserves are in the Middle East and former Soviet Union countries; just three countries — Russia, Iran and Qatar — hold 54% of the world total. Gas reserves (mostly conventional) in OECD countries amount to only 18 tcm, equal to about 10% of the world total, or 16 years of current OECD production.

Proven reserves represent only a small proportion of the total amount of gas resources that are thought to remain and that could be produced profitably at today’s prices and with current technology (recoverable resources). The scale of overall gas resources is not known with certainty, as many parts of the world have been poorly explored. This is especially true for unconventional gas, including shale gas, coalbed methane, tight gas (from low permeability reservoirs) and gas (or methane) hydrates. Based on data from the US Geological Survey (USGS) and from the German Federal Institute for Geosciences and Natural Resources (BGR), we estimate that remaining recoverable resources of conventional gas alone amount to 404 tcm.3 At end-2009, cumulative production (including flaring and venting) since gas production first began amounted to about 90 tcm, i.e. a little under one-fifth of ultimately recoverable conventional resources (the resources that existed before production began). As with proven reserves, the majority of remaining resources are in former Soviet Union countries and the Middle East (Figure 5.3). But unconventional gas resources could turn out to be even larger; excluding gas hydrates (for which commercial production technology has not yet been demonstrated), unconventional gas in place is estimated at over 900 tcm (IEA, 2009). Assuming around 380 tcm of this gas is recoverable, total recoverable gas resources would amount to close to 800 tcm — equivalent to about 250 years of current production. Unconventional gas resources are thought to be more widely dispersed geographically than conventional resources.

2. Preliminary data points to a 4.4% increase in proven reserves in 2009. 3. We have compiled data on resources for different basins around the world, drawing on the results of the last major resource assessment by the USGS in 2000, more recent updates of specific basins, new USGS assessments of basins not covered in the 2000 report, including a recent assessment of Arctic resources (USGS, 2008), and a 2009 study by BGR.

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5

Figure 5.3 z Proven reserves, recoverable resources and production of conventional natural gas by region in the New Policies Scenario 0

Projected global gas production in 2035 ranges from some 3 600 bcm to 4 900 bcm across the three scenarios, corresponding to demand in each case (Table 5.3). In the New Policies Scenario, demand reaches over 4 500 tcm, the rate of increase being tempered by policies to curb fossil-energy use and emissions. The lower prices in the 450 Scenario, resulting from weaker demand brought about by more far-reaching policy action, result in less investment and, therefore, lower production, to balance lower demand in that scenario. Production in the 450 Scenario actually peaks by the late 2020s, before going into steady decline. In the Current Policies Scenario, production grows quickest, and in a fairly constant fashion in absolute terms, as prices rise most rapidly (see Chapter 1). In all three scenarios, most of the increase in output occurs in non-OECD countries. Around 35% of the increase in global gas production in the New Policies Scenario comes from unconventional sources — mainly coal beds (coalbed methane), low-permeability reservoirs (tight gas) and shale formations (shale gas). Their combined share of production rises from around 12% in 2008 to about 19% in 2035 (Figure 5.4). The United States and Canada contribute more than one-quarter of the increase in absolute terms, 188

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with the bulk of the additional North American output coming from shale gas. US shale gas production has soared in recent years, from only 12 bcm in 2000 to an estimated 45 bcm in 2009, reversing the downward trend in the country’s overall gas output; indeed, overall, US gas production jumped 16% in the four years to 2009. This has largely eliminated the need for the country to import liquefied natural gas (LNG) to make good a previously expected shortfall in domestic gas supplies. This evolution has contributed to existence of surplus supply capacity in the rest of the world, brought about primarily by the global recession, and has been instrumental in driving down spot prices (see Spotlight and the section on trade below). Table 5.3 z Natural gas production by region and scenario (bcm) New Policies Scenario

OECD Non-OECD World Share of non-OECD

Current Policies Scenario

450 Scenario

1980

2008

2020

2035

2020

2035

2020

2035

889

1 157

1 158

1 188

1 173

1 203

1 103

1 033

640

2 010

2 636

3 347

2 661

3 685

2 480

2 577

1 529

3 167

3 794

4 535

3 835

4 888

3 584

3 609

42%

63%

69%

74%

69%

75%

69%

71%

bcm

Figure 5.4 z World natural gas production by type in the New Policies Scenario 5 000

Note: Tight gas production is defined and reported in different ways across regions, so the data and projections shown here are subject to considerable uncertainty, indicated by the shading.

The prospects for unconventional gas production in the rest of the world, tiny for now, remain very uncertain, though they have improved over the past year with growing interest in several parts of the world. Output is projected to grow most in China, India and Australia (where coalbed methane production has grown rapidly in recent years). Exploration drilling for shale gas and coalbed methane has begun in Europe, notably in Poland, and some tight gas prospects have also been identified in Poland, Hungary and Germany (IEA, 2010). But unconventional production there is likely to remain relatively Chapter 5 - Natural gas market outlook

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5

modest in the medium term, mainly because of the logistical and administrative difficulties in gaining access to land, and environmental concerns related to the need for large volumes of water for hydraulic fracturing and the risk of groundwater contamination (IEA, 2009). The uncertainty surrounding unconventional gas supplies outside North America is nonetheless very large. There is a risk that industry expectations of rapid expansion in unconventional supplies could inhibit investment in conventional resources, leading to a shortfall in overall gas supply and temporary upward pressure on prices. Conversely, more rapid development of unconventional gas supplies than projected here could lead to lower gas prices relative to oil, and more rapid penetration of gas in the power sector and in final uses.

In the New Policies Scenario, the Middle East makes the largest contribution to the expansion of gas production over the Outlook period, its output more than doubling to close to 800 bcm by 2035 (Table 5.4 and Figure 5.5). The region holds the largest reserves and has relatively low production costs, both for gas produced in association with oil and for dry gas. Four countries — Qatar, Saudi Arabia, Iran and Iraq — account for almost all of the 410-bcm increase. Around two-thirds of the increase in output, or 275 bcm, is consumed locally, mainly in power stations; the remaining 130 bcm is exported (see section on inter-regional trade). Although there is little doubt that these countries have the resources to increase production substantially, there is considerable uncertainty about when and how quickly this will happen, especially in Iraq and Iran. Qatar has declared a moratorium on new gas-export projects, pending the outcome of a study of the effects of current projects on the reservoirs of the country’s North Field — the world’s largest gas field. Most Middle East countries, with the exception of Qatar, have encountered shortages of gas in recent years, as exploration and development has failed to keep pace with demand. Eastern Europe/Eurasia sees the second-biggest volume increase in output over the projection period (see Chapter 17 for a detailed discussion of Caspian gas production prospects). It remains the largest single producing region in 2035, well ahead of North America, with Russia and Turkmenistan pushing up the region’s production. Asia and Africa account for most of the remaining increase in world output between 2008 and 2035. China is projected to see a sizeable expansion of its capacity, with the bulk of the increase in the longer term coming from tight gas deposits, coalbed methane and shale gas. Total gas production there reaches almost 140 bcm in 2020 and 180 bcm in 2035, up from only 80 bcm in 2008. The China National Petroleum Corporation has entered into joint ventures with a number of international companies to develop technically challenging resources. China signed an agreement with the United States in November 2009 to co-operate on shale gas development, Chinese resources of which are thought to be very large. Despite this projected increase in production, China’s import dependence still rises over the projection period, especially after 2020. India is also set to increase gas output, though the pace of development is expected to slow in the medium term. Production surged in 2009, to an estimated 46 bcm, with the completion in late 2008 of Reliance’s D6 block in the Krishna Godavari basin. Output is projected to grow to 60 bcm in 2015, with additional output from D6 more than offsetting declines at other, mature fields, and to just over 100 bcm by 2035, with a growing share coming from unconventional 190

World Energy Outlook 2010 - GLOBAL ENERGY TRENDS

sources (notably coalbed methane) as conventional resources are depleted and development costs rise with declining field size. Most of the increase in African gas production occurs in Algeria and Nigeria. Table 5.4 z Natural gas production by region in the New Policies Scenario (bcm) 1980

Among the OECD regions, production in North America rises by around 50 bcm between 2008 and 2035, mainly due to unconventional supplies (notably shale gas), but in Europe falls by 100 bcm to 210 bcm, as declines in North Sea production in the United Kingdom and Netherlands more than outweigh continued growth in Norway. Australian production grows strongly, more than tripling over the projection period, driven mainly by LNG export projects. Australia overtakes Norway towards the end of the projection period to become the third-biggest OECD gas producer, behind the United States and Canada. Coalbed methane accounts for a growing share of Australian supply, with the first LNG projects based on such gas likely to proceed in Queensland in the next few years.

International trade in natural gas is set to grow rapidly in the coming quarter of a century. In the New Policies Scenario, inter-regional gas trade (between all WEO regions) expands by more than three-quarters from 670 bcm in 2008 to nearly 1 200 bcm in 2035 (Table 5.5), outpacing the projected 43% increase in global production. Imports into OECD North America, OECD Europe and both OECD and developing Asia grow in volume terms. China’s imports grow the most, from a mere 5 bcm in 2008 to close to 80 bcm in 2020 and over 200 bcm in 2035. In fact, China accounts for a stunning 40% of the growth in inter-regional trade over the Outlook period. Within North America, the United States remains a net importer of gas, mainly from Canada, though its imports fall over the projection period. Net EU imports grow by 58%, from 320 bcm in 2008 (and an estimated 310 bcm in 2009) to just over 500 bcm in 2035. Africa, the Middle East, Russia, Australia and the Caspian account for the bulk of the increase in exports. More than half of the growth in gas trade will be in the form of LNG. Trade in LNG more than doubles between 2008 and 2035, reaching 500 bcm, or 11% of world demand in the New Policies Scenario; most of the incremental LNG supply goes to Asia (Figure 5.6). 192

* Production for exporting regions/countries. ** Total net exports for all WEO regions/countries (some of which are not shown in this table), not including trade within WEO regions. Note: Positive numbers denote exports; negative numbers imports.

The share of LNG in total gas trade rises from 31% in 2008 to 35% in 2020 and 42% in 2035 (Figure 5.7). Eight LNG liquefaction projects are under construction, all of which are due to be commissioned by 2015, adding 77 bcm to current capacity of around 360 bcm (at end-June 2010).4 Close to 30% of this increase will come from Qatar, where two more large trains will be commissioned before the end of 2011 to supplement the four that started up between 2009 and early 2010. The rest of the capacity additions will come from Algeria (Gassi Touil and Skikda), Angola, Australia (Pluto and Gorgon) and Papua New Guinea. A number of other projects are also planned, notably in Australia.

4. Capacity at end-2009 was 338 bcm; one plant in Qatar and another in Peru, together with a second train in Yemen, were commissioned during the first half of 2010.

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5

2008

2

7

2020

3

2035

9 5 15 8

OECD North America Latin America

5

15 22

14 18

* Only flows above 4 bcm are shown.

41 45 49

Africa

4

18 29 44

60 26

Other Asia OECD Oceania

OECD Asia

10 27

11 41 43

5 16

16 5

India China

11 21

40

Middle East

32

9

6

Eastern Europe/Eurasia

36

11 50 62

45 94

12 19

OECD Europe

6

83 98 138

154 174 215

The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA.

As a result of the economic crisis, which depressed gas demand around the world, together with the unexpectedly strong growth in unconventional gas production in the United States in the last few years, a sizeable glut of gas-supply capacity has developed. This has led to a sharp fall in the utilisation rate of existing pipeline and LNG capacity, which has been expanding rapidly in recent years (the investment decisions on most new projects recently completed or still under construction were taken well before the crisis began). Based on projected demand in the New Policies Scenario, we estimate that this gas glut, measured by the difference between the total capacity of inter-regional pipelines and LNG export plants and total interregional trade, reached about 130 bcm in 2009 (compared with 80 bcm in 2007) and could peak at over 200 bcm in 2011, before commencing a slow and hesitant decline (Figure 5.8). The capacity utilisation rate would fall from an estimated 75% in 2009 (83% in 2007) to under 70% in 2011, before recovering to about 75% in 2014. This suggests that the gas glut will last longer than many exporters believe or hope, keeping pressure on them from their major customers to modify pricing arrangements (see the earlier Spotlight). This pressure is likely to be greatest in Europe, where demand is expected to recover less quickly than in Asia-Pacific. Our analysis suggests that it may take several years for the gas glut to be fully eliminated. Even if no new pipeline or LNG project is commissioned before 2020 beyond those projects that have already obtained a final investment decision — which is highly unlikely — unused capacity would still total more than 150 bcm and the utilisation rate would still be only 80% by 2020.5

5. In part, it is to be expected that utilisation rates will not recover fully to the levels reached in the mid2000s, as part of the incremental pipeline capacity that is being built is designed to substitute for, rather than supplement, existing capacity: this is especially the case with new Russian export lines to Europe. Also, the availability of gas to supply some existing pipelines, to which they are dedicated, will tend to fall as the source fields mature and production declines.

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bcm

Figure 5.8 z Natural gas transportation capacity between major regions in the New Policies Scenario 800

Box 5.1 z The GECF seeks oil price parity and ponders how to achieve it The Gas Exporting Countries Forum (GECF), which became a full-fledged international organisation in 2008, agreed at a meeting in Algeria in April 2010 to strive for gas price parity with oil and for the removal of “unjustified barriers”, such as carbon taxes, to the increased use of gas. Prices of gas traded on a spot, or short-term, basis have fallen heavily relative to oil since 2008, as a result of a slump in demand and increased supplies of unconventional gas in the United States and of LNG, though the price of most internationally traded gas remains tied to oil under long-term contracts. Although no specific measures to achieve price parity were formally proposed at the meeting, Algeria had previously indicated that one option would be to agree on co-ordinated cutbacks in production, raising concerns among gas-importing countries about the prospective cartelisation of the gas market, with the GECF becoming a “Gas OPEC”. GECF countries collectively control around two-thirds of the world’s proven gas reserves, though several members currently make little or no contribution to international gas trade. However, such co-ordinated cutbacks would be difficult to achieve, particularly in the near term, not least because of volume commitments in long-term contracts and because of the relative ease with which other fuels could substitute for gas in power generation and end uses. The GECF will continue to emphasise information-sharing and dialogue for now, but may seek a more proactive role in market-related issues in the longer term. Bilateral co-operation between individual GECF members may prove as important as what happens under the GECF umbrella.

Investment The projected trends in gas demand in the New Policies Scenario would require a cumulative investment along the gas-supply chain of about $7.1 trillion dollars (in year 2009 dollars), or around $270 billion per year (Table 5.6). Roughly two-thirds of 196

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that capital spending, or $175 billion per year, is needed upstream, for new greenfield projects and to combat decline at existing fields.6 LNG facilities account for about 9% of the total, and transmission and distribution networks for the rest. Unsurprisingly, the majority of the investment is needed in non-OECD countries, where local demand and production grows the most. Table 5.6 z Cumulative investment in gas-supply infrastructure by region and activity in the New Policies Scenario, 2010-2035 ($ billion in year-2009 prices) Exploration and development

* World total includes an additional $74 billion of investment in LNG carriers.

6. Together with investment in oil, this level of gas investment yields a total upstream investment requirement of around $450 billion per year on average over 2010-2035. This compares with planned total upstream oil and gas investment worldwide in 2010 of $470 billion (see further discussion of upstream investment trends in Chapter 3). A shift in investment towards relatively low-cost regions, notably the Middle East, outweighs the effect of rising overall production over the projection period.

z In the New Policies Scenario, demand for coal increases by around 20%

between 2008 and 2035, with almost all of the growth before 2020. Demand is significantly higher in the Current Policies Scenario and much lower in the 450 Scenario, reflecting the varying strength of policy action assumed to address climate change and underscoring the need to significantly reduce emissions from coal use if it is to remain a mainstay for base-load power supply. z Non-OECD countries as a group account for all of the growth in global coal

demand in the three scenarios of this Outlook. In the New Policies Scenario their share of total demand increases from 66% today to 82% by 2035. China, India and Indonesia account for nearly 90% of the total incremental growth, highlighting their crucial influence on the future of the coal market. China remains the world’s largest consumer of coal, while India becomes the second-largest around 2030; Indonesia takes fourth position (behind the United States) by 2035. Over the projection period, China installs around 600 GW of new coal-fired power generation capacity, comparable with the current combined coal-fired generation capacity of the United States, the European Union and Japan. z Global coal production in the New Policies Scenario grows from just under

4 900 Mtce in 2008 to just above 5 600 Mtce in 2035. China accounts for half of global coal production by 2035, while Indonesia’s output overtakes that of Australia. Global hard coal trade rises in the medium term, before declining to around 840 Mtce in 2035, although this is still 15% higher than today. z Cumulative investment to meet projected coal demand through to 2035

amounts to some $720 billion (in year-2009 dollars) in the New Policies Scenario. Two-thirds takes place in non-OECD regions, with China alone needing over $260 billion. Global investment by 25 leading coal companies rose by 4.5% in 2009 to about $12 billion; this compares with a surge of 18% in 2008.

z China will continue to have a crucial influence on global coal trade. The country

has been turning increasingly to imports in recent years, as domestic supply has struggled to keep up with rapidly rising demand. It is now working to overcome transportation bottlenecks and to speed-up the development of its vast coal resources in the northern and western parts of the country. Given the sheer size of China’s market, the uncertainty around its future supply-demand balance will have major implications for trade patterns and prices of internationally traded coal.

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Demand Primary coal demand trends Demand for coal remained fairly solid in 2009, despite the global economy going through an upheaval (oil and gas demand, by contrast, fell substantially). The three scenarios in this year’s Outlook clearly demonstrate the critical influence of government policies, especially those related to climate change, on the outlook for coal demand (Figure 6.1). In the Current Policies Scenario, which assumes no change in government policies, strong global economic growth and near tripling of electricity demand in non-OECD countries lifts global coal demand to over 7 500 million tonnes of coal equivalent (Mtce) by 2035, or nearly 60% higher than in 2008. In contrast, world coal demand in the New Policies Scenario, which takes into account planned reforms of fossil-fuel subsidies, implementation of measures to meet climate targets and other planned energy-related policies, is around 1 925 Mtce, or a quarter, lower in 2035. This difference is equal to about China’s current total coal demand, or 40% of global coal demand in 2008. In the 450 Scenario, which assumes more decisive implementation of policy plans and a further strengthening of policies after 2020, with the objective of limiting to 2°C the long-term rise in the global average temperature, world coal demand at about 3 565 Mtce in 2035 is a quarter lower than the level in 2008 and close to the levels of the 1990s and early 2000s.

Coal use in the OECD falls in all three scenarios between 2008 and 2035, as countries further decarbonise their electricity generation mix, not returning to the peak consumption levels seen before the global financial crisis that began in 2008 (Table 6.1). OECD coal demand is estimated to have contracted by 10% in 2009, with more than 50% of this decline occurring in the United States. By 2035, in the New Policies Scenario, the OECD accounts for less than one-fifth of global coal demand, compared with one-third today, its coal demand declining on average by 1.7% per year 200

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over the projection period. Thus, non-OECD countries account for all of the growth in global coal demand, raising their share in the worldwide market from 66% today to 82% by 2035 in the New Policies Scenario. While non-OECD coal demand grows by 1.4% per year over the Outlook period in this scenario, on a per-capita basis it grows by only 0.4% per year. Today, annual coal consumption per head in the non-OECD is on average 0.57 tonnes of coal equivalent (tce), around 40% the level in the OECD. By 2035, in the New Policies Scenario, OECD per-capita annual coal consumption has fallen to 0.78 tce, but is still around one-fifth higher than in the non-OECD countries. By 2035 non-OECD coal intensity in the New Policies Scenario, measured as coal use per unit of GDP at market exchange rates, has more than halved relative to today’s levels but is still more than double that of the OECD in 2008, leaving room for further intensity gains and lower coal demand, as demonstrated by the 450 Scenario of this Outlook (see Chapter 14).

Regional trends In 2008, China, the United States, the European Union, India, Russia and Japan accounted for 83% of global coal demand (Figure 6.2). These six demand centres accounted for almost 70% of global GDP and energy-related CO2 emissions and just over half of the world’s population in 2008. Within this group, the relative importance of the countries has changed significantly since 1990. Two decades ago, the United States, the European Union, Russia and Japan accounted for just over half of global coal demand: in the past decade, China, alone has become the dominant consumer. China’s coal consumption, which grew by 1 120 Mtce over the last eight years, accounted for more than three-quarters of global coal demand growth in the period 2000-2008. As a result, China today accounts for 43% of global coal demand and by 2035, in the New Policies Scenario, China’s share reaches 50%. China and other Asian economies with large populations and strong economic growth, such as India and Indonesia, will accordingly have a crucial influence on the future of the coal market, not only in terms of demand but also of production and trade. Among the regions where coal demand increases over the projection period in the New Policies Scenario, China, India and Indonesia together are responsible for nearly 90% of the total growth. Chapter 6 - Coal market outlook

The United States, the European Union, Russia and Japan all see their coal demand decline over the projection period in the New Policies Scenario, their combined market share plunging from 33% today to 18% by 2035. The European Union’s coal demand declines fastest, at 3% per annum (Table 6.2). In all four of these demand centres, the share of coal in total primary energy demand declines, as coal is displaced by gas, renewables and nuclear in electricity generation or by electricity and gas in industrial processes. By 2035, one-third of electricity in the United States is generated from coal, compared with nearly half today, as the share of renewables and, especially, that of wind grows from 1.3% today to 10% by the end of the Outlook period. In the European Union, the share of coal in electricity generation declines by 2035 by almost 20% compared to 2008, as the share of renewables grows from 17% to 41%. In Russia and Japan, nuclear makes strong inroads at the expense of coal in electricity generation, especially in Japan where the share of nuclear power goes from 24% to 42% by 2035 (see Chapter 7). Coal demand in China, the world’s largest consumer of coal, grows by 2.7% per year to 2020 in the New Policies Scenario, but then remains fairly stable through the rest of the projection period at a level of around 2 800 Mtce. The share of coal in China’s total primary energy demand declines from 66% today to 53% by 2035. Continued growth in demand from the power generation sector in China, albeit at a slower pace than historically, is offset by a fall in coal demand for industry, which peaks before 2020 and soon after begins to decline. Over the projection period, China brings on-line around 600 gigawatts (GW) of new coal-fired power generation capacity, comparable with the current combined coal capacity of the United States, European Union and Japan. In China’s industrial sector, about 60% of energy demand currently comes from coal, while electricity accounts for a further quarter. In the New Policies Scenario, coal’s share declines to 42% by 2035. Almost two-thirds of the growth in energy use in industry is met through electricity, while gas doubles its market share in China. 202

Over the projection period, India becomes the world’s second-largest consumer of coal around 2030, with demand doubling from around 370 Mtce today to 780 Mtce by 2035 in the New Policies Scenario. More than half of the incremental coal demand in India comes from the power sector, as the nation strives to improve the welfare of the nearly 405 million citizens — one-third of the total population — who at present lack access to electricity and the 855 million citizens who rely on traditional biomass for cooking (see Chapter 8). Another 38% of the projected increase in India’s coal demand comes from the industrial sector, raising the share of coal in that sector from around one-third today to above 40% by 2035. Despite the strong projected growth in coal demand, the share of coal in India’s total primary energy demand declines from 42% today to 39% by 2035, as coal loses market share to renewables, gas and nuclear in the power generation sector. Indonesia, traditionally considered mainly as a steam-coal exporter, sees its domestic demand tripling to nearly 170 Mtce by 2035, a rate of growth of 4.4% per year, by far the highest among all the major regions. Today, Indonesia is only the 13th-largest Chapter 6 - Coal market outlook

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coal consumer; in the New Policies Scenario, it overtakes Japan, today the 5th-largest consumer, by 2025 and Russia by 2035 to become the world’s 4th-largest coal-consuming country. Indonesia today is the world’s fourth most populous country and by far the largest economy in the Association of Southeast Asian Nations (ASEAN). Indonesia experiences frequent electricity blackouts and only 65% of the population has access to electricity, which places a severe constraint on development (IEA, 2009). The power sector accounts for nearly 60% of the growth in projected domestic coal demand in the New Policies Scenario, as coal-fired capacity more than quadruples to 46 GW by 2035. Coal demand grows in most other non-OECD regions, apart from Eastern Europe/ Eurasia, where it declines by 0.4% per year over the projection period in the New Policies Scenario. Within that group, the Caspian region bucks the trend by increasing its demand for coal. Kazakhstan — the world’s 15th largest consumer and 10th largest producer of coal today — remains the main coal-consuming country in the Caspian region (see Chapter 16). In 2009, a sharp fall in exports to Russia, coupled with growth in domestic demand, saw coal production in Kazakhstan drop around 10%, highlighting the close link between the country’s export potential and Russian demand.

In 2008, nearly two-thirds of global coal demand was consumed in the power sector and another one-fifth in the industry sector. The share of coal in industrial energy use has declined only slightly since 1990, while the share in the power sector has grown by 10 percentage points, mainly at the expense of the buildings and agriculture sector, which in 1990 consumed just over 10% of global coal demand. Over the Outlook period, as global coal demand grows by 0.6% per year in the New Policies Scenario, each sector’s share of demand remains roughly similar. Demand in power generation accounts for almost 60% of the increase of 885 Mtce in global coal demand, while another 30% of the demand growth comes from the industry sector (Figure 6.3). Coal-to-liquids (CTL), a means of reducing oil-import dependency, emerges as an important growth sector, with demand increasing by around 125 Mtce (equivalent to 45% of the growth in global industrial coal use) as just over 1 million barrels per day (mb/d) or 1% of global oil demand by 2035 in the New Policies Scenario is obtained through CTL (see Chapter 4). Coal transformation is not limited to CTL. Coal gasification is already successfully undertaken in China, South Africa and the United States to produce syngas, and underground coal gasification holds the potential of providing a means of exploiting coal deposits which are not mineable using conventional techniques (Box 6.1). Almost 90% of the decline of 590 Mtce in OECD coal demand over the projection period in the New Policies Scenario is expected to result from new policies to decarbonise the power sector in order to reach the targets proposed under the Copenhagen Accord. Over the Outlook period, around 390 GW of coal-fired generation capacity is expected to cease operating in the OECD, an amount greater than today’s combined installed coal-fired generation capacity of OECD North America. Offsetting this to an extent, over the same time frame 255 GW of new coal-fired capacity is expected to be built in the OECD, of which 92 GW would employ highly efficient ultra-supercritical or integrated gasification combined-cycle (IGCC) technologies and an additional 33 GW would incorporate means to capture and store CO2. By contrast, about 70% of 204

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the growth in non-OECD coal demand of 1 475 Mtce is projected to come from power generation, with China, India and Indonesia being responsible for 61%, 21% and 6% of the growth respectively. Just over 1 100 GW of new coal-fired generation capacity, close to double today’s coal-fired generation capacity in China, is installed in the non-OECD over the projection period. A further 20% of the increase in non-OECD coal demand comes from the industrial sector, with India alone accounting for nearly half of this. Figure 6.3 z Change in primary coal demand by sector and region in the New Policies Scenario, 2008-2035 OECD Power generation

Box 6.1 z Coal gasification The surge in the production of tight and shale gas in the United States over the past decade has had a profound impact on the global gas market outlook (IEA, 2009). Technologies similar to those used for shale gas production can be applied to extracting energy from coal seams. In last year’s Outlook, the prospects for coalbed methane (CBM) production, extracting methane from coalbeds that are not mined due their depth or poor quality, were examined in detail. In the New Policies Scenario, CBM production is expected to contribute nearly 200 billion cubic metres (bcm), or 15%, towards global incremental production of gas (see Chapter 5). However, only a small fraction, around 1%, of the total energy stored in a coal seam is recovered during CBM production. Underground coal gasification (UCG) has the potential to recover much more energy and is of particular interest at coal deposits which are un-mineable using conventional techniques. If successful, UCG would substantially increase the proportion of the world’s coal resources that could be classified as recoverable. UCG involves an injection borehole, through which air or oxygen (and possibly steam) are injected, and a production well from which product gas (mainly hydrogen and carbon monoxide) is drawn to the surface for treatment and use. The boreholes are linked by a zone through the coal seam where coal combustion

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and gasification takes place in a continuously changing combustion zone that must be monitored and controlled. Commercial-scale operation would involve multiple wells. The technique has a long history in the Former Soviet Union, where it was carried out on an industrial scale, and trials have taken place in the United States, Europe and China. Recent pilot-scale tests in Australia, Canada, China and South Africa have built on developments in directional drilling and computer modelling. Successful results could be expected to spur activity in other countries rich in coal resources, including India, Poland, Russia, the United Kingdom and the United States. Results from current pilot projects are sketchy because some knowledge is proprietary. For example, little is yet publicly known about what happens to the surrounding geology and hydrogeology when a combustion zone at 1 000°C moves through a deep coal seam. This is unfortunate because there are formidable obstacles to be overcome to integrate the knowledge from different disciplines to the point where a project can be designed with confidence that it will perform as intended. Only some 15 to 20 million tonnes (Mt) of coal have been gasified underground to date, which illustrates the limited experience with UCG. In view of the scale of the prospective rewards, UCG project developers need to consider how to move quickly from pilot projects at carefully chosen and favourable sites to more ambitious demonstration projects that can provide the design basis for large commercial projects in a wide range of coal types and situations. Co-operation between developers and government-supported research and development could speed progress and increase confidence in UCG technology. Coal gasification (CTG) was once the main source of town gas for use in cities. The processes used were reliable, but polluting. Technological advances mean that coal gasification is carried out today using continuous processes that produce clean synthesis gas for chemicals and liquid fuels production, or for other uses, at many plants around the world, notably in China, South Africa and the United States. As demand for gas grows, coal gasification could become a competitive source in regions with access to low-cost coal reserves, such as Xinjiang in China. According to Platts, there are 15 coal-to-gas projects in China under construction or being planned. Huineng Group’s project in Inner Mongolia and Datang Power International’s two 4 bcm/year projects in Chifeng and Fuxin recently won approval from China’s National Development and Reform Commission. Sources: IEA CCC (2009); Platts.

Resources and reserves According to the German Federal Institute for Geosciences and Natural Resources, coal resources make up an estimated 82% of the world’s non-renewable energy resources (BGR, 2009). Of this resource, reserves totalling nearly 1 000 billion tonnes 206

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are sufficient to meet demand for many decades: at present coal production levels, reserves would meet demand for almost 150 years. Coal reserves are widespread, but the largest reserves are in a small number of countries, notably the United States, China, Russia, India and Australia. Unlike oil and gas, coal exploitation has not been generally constrained by resource nationalism, except in Venezuela. A well established international coal market ensures that demand is met from the most economic suppliers, around 15% of hard coal production was traded between countries in 2008. Undoubtedly, as demonstrated in this Outlook, where global coal demand grows by 1.7%, 0.6% and -1.0% on average over 2008-2035 in the three scenarios, the limit to continued growth in the use of coal does not lie in scarcity of resources, but depends rather on how coal’s carbon intensity can be reconciled with the growing global momentum to stabilise greenhouse-gas emissions at a sustainable level.

Coal production prospects In the New Policies Scenario, global coal production is projected to increase by about 740 Mtce reaching 5 620 Mtce by 2035 (Table 6.3). Most of the growth occurs in non-OECD countries. Reflecting the underlying demand trends, nearly all the incremental growth in global coal production comes in the form of steam coal; coking coal production expands by about 5% by 2035 compared to today; brown coal production declines by 20 Mtce by the end of the projection period relative to 2008 levels.

Coal production fell in most OECD countries in 2009 in reaction to weak demand, with only Australia, the Slovak Republic and the United Kingdom showing any growth. Coal output in the United States fell by 9%, in response to weak electricity demand and competition from natural gas. In OECD Europe, coal production fell by almost 7%, notably in Poland and Germany, where the government and industry have adopted an agreed plan to phase out hard coal production by 2018. In line with a projected average decline in OECD demand of 1.7% per year in the New Policies Scenario, production in most OECD regions is expected to decline over the projection period; the main exception is Australia, where growth in export demand increases production by 0.6% per year. To meet growing electricity and industrial demand, China’s coal production grows on average by 1.1% per year to reach 2 825 Mtce in 2035, equal to one-half of global coal output and 35% higher than in 2008. By any measure, the story of coal in China is remarkable. The annual production capacity of new coal mines under construction is estimated to be 200-300 Mt, comparable to the European Union’s annual hard coal consumption. In China’s latest Five-Year Plan, which envisages a rise in coal production to 3 600 Mt by 2015, Xinjiang is identified as a province for future coal exploitation (see Spotlight). Shenhua Group and other Chinese coal companies have announced plans to invest in this region and, although it is remote from demand centres, coal output there could grow to 1 000 Mt to feed coal conversion processes, such as electricity generation, chemicals production and synthetic fuels manufacturing. Chapter 6 - Coal market outlook

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S P O T L I G H T

Is Xinjiang destined to become the Ghawar of coal? Xinjiang is a sparsely populated, autonomous region on the north-western frontier of China, with borders extending north to Russia and west to Central Asia. As China’s largest administrative region, accounting for 17% of the nation’s surface area, Xinjiang covers an area comparable to that of Iran. The region has vast mineral wealth, which could contribute crucially to China’s energy needs. In addition to large oil and gas deposits, Xinjiang is significantly rich in coal, with an estimated 2.2 trillion tonnes of resources, or around 40% of China’s total. However, as the region is far from major energy-consuming centres in the coastal areas, its coal resources have so far been largely untapped. Mining has been directed to meeting local demand and in 2009 output was around 90 Mt, or less than 5% of China’s total production. There is an expectation that Xinjiang will play an increasingly important role in meeting China’s coal demand in the decades ahead. As part of its long-term strategy to promote economic growth in the west of the country, in order to raise living standards and shift growth away from the more prosperous coastal areas, China is promoting the development of Xinjiang’s vast coal resources. This will help offset losses in production from resources in eastern regions which are being steadily depleted and smooth the way for closure and consolidation of smaller mines throughout the country for safety and environmental reasons.

The major impediment to developing Xinjiang’s coal resources has been bottlenecks in transport capacity between its mines and demand centres in the east. But for a number of years now the Chinese government has been working with Xinjiang to address this constraint. Construction of a new rail link running from Xinjiang to the inland provinces of Gansu and Qingha is set to be completed in 2013 and it will allow the existing line to be dedicated exclusively to freight. Xinjiang’s regional government expects that the upgraded railway network will permit an increase in the region’s coal output to 500 Mt in 2015 and 1 000 Mt in 2020. By that time, Xinjiang’s contribution to global coal production could be double the contribution that Ghawar — the world’s largest oil field — currently makes to global oil production. In addition to increasing coal production, Xinjiang has initiated other projects to use coal to fuel its economic development. It is rapidly expanding its power generating capacity, much of which will be dedicated to delivering electricity to the eastern provinces. Consistent with China’s push to minimise reliance on costly imports of natural gas, it is also pushing ahead with the development of coal gasification projects. If Xinjiang’s plans for expanding its coal production are fully realised, there would be major repercussions for global markets. It could help China revert to being a net-exporter of coal, which could be expected to put considerable downward pressure on the prices of internationally traded coal and impact the plans of other coal exporters.

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Table 6.3 z Coal production by region in the New Policies Scenario (Mtce) 1980

Indonesia’s production increased by an estimated 10% in 2009 over 2008 and is expected to continue growing in the future to satisfy domestic and export demand, as mining companies move to exploit reserves further inland. In 2009, China became the largest importer of Indonesian coal, having been a relatively minor importer in previous years. While the Indonesian government plans to give domestic demand priority over exports, the mining industry appears confident it can easily satisfy both growing export demand and local demand from planned new power projects. In the New Policies Scenario, Indonesian production increases by 70%, to reach 400 Mtce by 2035, a level exceeding the projected output of Australia. Production elsewhere in Asia, including India whose production increases by around 55% from today’s levels, is projected to rise in response to strong domestic demand and in certain cases, like that of Mongolia, to satisfy export demand. Chapter 6 - Coal market outlook

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Russian coal production fell in 2009, reflecting the difficult economic situation, but exports increased by 20%, including to the distant Asian market through the ports of Vostochny and Siberian Coal Energy Company’s (SUEK) newly expanded Vanino port. The construction of a second terminal at Muchka Bay is in progress and a new 317 kilometre rail line is under construction, linking coal reserves in the Sakha (Yakutia) Republic to the eastern ports. A projected decline in domestic demand of 0.2% per year, coupled with significant declines in demand in traditional markets in Europe, are expected to result in Russia’s production declining to just under 195 Mtce by 2035 in the New Policies Scenario. Output in South Africa in 2009 is estimated to have declined by 2%. Its future level of exports will depend on the relative priority given to coal production for export, given the rising domestic demand for electrification. Coal production in the New Policies Scenario for Africa as a whole is projected to grow by 0.3% per year over the projection period, South African production remaining similar to today’s levels, while in Mozambique, Botswana and elsewhere new coal production prospects emerge. Colombian coal exports are estimated to have grown by 2% in 2009. The potential to export over 100 Mt per year exists as a result of the construction by MPX, a Brazilian company, of a new port at Dibulla. Exports to Asia are expected to grow, despite the long shipping distances. Some Colombian coal will also transit the Panama Canal, which will be able to accommodate larger vessels when expansion is completed in 2014. In Venezuela, strikes and bad weather hindered production in 2009, which fell by 40%. The outlook is constrained, since the government has stated that production should not exceed 10 Mt and mining concessions will not be renewed, as part of the planned nationalisation of the mining industry. In line with projected domestic demand and global net-trade in the New Policies Scenario, Latin American production is expected to increase in the medium-term, before stabilising around 100 Mtce over the second-half of the projection period.

The patterns of coal trade shifted markedly in 2009, as the Asian market consolidated its dominance of global trade. Whereas Japan and South Korea have long been the world’s largest coal importers, the non-OECD economies of China, Chinese Taipei and India are now just as significant. While the overall level of global coal trade changed little from 2008, significant growth in the Pacific market was offset by a decline in the Atlantic market. China’s imports of hard coal tripled in 2009 to reach 137 Mt, while exports fell sharply from 45 Mt to 23 Mt, resulting in China becoming a net importer for the first time — a development foreseen three years ago, though the pace of growth of imports in 2009 was unexpected (IEA, 2007). Australia, Indonesia and Vietnam have been the main sources of China’s imports, but China’s growth has affected the international coal market as whole, with Colombian coal being shipped to China for the first time. The future extent of China’s net imports of coal remains highly uncertain, hinging principally on coal demand in coastal areas and the relative competiveness of imported 210

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coal and gas against domestic sources of coal. Securing future fuel supply for power generation is of crucial importance for China’s coastal region, which requires large amounts of electricity for its economic development. But as resources are scarce in the region, large amounts of fuel must be brought in from within and outside China. Imports of natural gas are expected to rise over the coming decades. Three liquefied natural gas (LNG) terminals are already in operation and six additional are being constructed in the coastal provinces; a natural gas pipeline from Turkmenistan was also commissioned in 2009. While priority for natural gas use is at present given to the residential and industry sectors, more gas is expected to be used in power generation in the future, as import capacity increases (see Chapter 5 and Chapter 18). The price of LNG imported into China, which varies at present from 4 to 12 dollars per million British thermal units ($/MBtu), will be the key factor. The generating costs of power plants using imported LNG and coal determine the mine-mouth coal costs required for domestic coal to be competitive (Figure 6.4). For example, assuming an imported coal cost of 90 dollars per tonne ($/t), power plants using indigenous coal from a mine within 500 kilometres (km) remain competitive at mine-mouth costs lower than around $65/t. However, should the imported coal cost be on the lower level of $60/t, mine-mouth costs lower than around $40/t would remain competitive.

In the New Policies Scenario, global trade in hard coal among WEO regions is projected to rise from 728 Mtce today to just under 870 Mtce before 2020, before decreasing to settle at a level around 840 Mtce as global demand for coal stabilises over the secondhalf of the projection period (Table 6.4). By 2035, inter-regional trade meets 16% of global hard coal demand, a level similar to today. On average the value of global hard coal trade over the period 2010-2035 is equal to $125 billion (in 2009 dollars) per year, while that for oil and gas amounts to around $1 580 billion and $410 billion, respectively. Net exports from high-cost producing countries, like the United States and Russia, decline over the projection period, while net exports from Australia and Indonesia increase, by just over 70 Mtce and 50 Mtce, respectively. India’s net Chapter 6 - Coal market outlook

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imports increase five-fold to reach 280 Mtce by 2035, while China swings from being a net importer in the short and medium term to a net exporter by 2035, in response to stabilisation of domestic demand at around 2 830 Mtce in the second-half of the Outlook period and continued strong domestic output growth. Table 6.4 z Inter-regional hard coal* net trade by region in the New Policies Scenario (Mtce) 2008 Mtce

* Steam and coking coal (including coke). ** Production for exporting regions/countries. *** Total net imports for all WEO regions/countries (some of which are not shown in this table), not including trade within WEO regions. Note: Positive numbers denote export; negative numbers imports.

Compared with 2007, the cost of producing steam coal for the international market rose by around $10/t across most regions in 2008, due to the higher cost of diesel, labour, steel, spare parts and other factors (IEA, 2009). But, in 2009, there appears to have been little change in the average cash cost of internationally traded coal (Figure 6.5). Based on this coal supply cash-cost curve, the weighted-average cost is around $43/t across all countries, with Indonesia, the largest exporter of steam coal, 212

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remaining one of the lowest cost producers. One key issue is the movement in costs relative to the average free-on-board (FOB) prices for 2009. The fall in FOB prices since the peak of 2008, coupled with rising costs as supply chains became stretched and infrastructure constrained, squeezed margins significantly. FOB prices in the Asian market are already rising in 2010 in response to a rise in demand from Pacific market economies, while prices in the Atlantic market have remained relatively soft due to lower demand for electricity, resulting from the economic downturn. Coal futures suggest prices will rise over the next four to five years as the world emerges from the recent economic crisis, as reflected in the underlying assumptions in this Outlook (see Chapter 1). During 2009, large discrepancies were observed between coal prices around the world. The highest prices could be found at Chinese ports, which translated back to high FOB prices at Australian ports. This lifted South African coal export prices, which rose above European import prices, a trend that continued during the first half of 2010, resulting in a lack of demand in Europe for South African coal. Colombia has faced the lowest export prices, because of low demand from North America and Europe. Coking coal prices have traditionally been set during annual negotiations with Japanese steel producers, with other steel producers largely accepting the outcome. This archaic system is gradually being replaced by more transparent marketbased pricing.

Current trends Investments by 25 leading coal companies, which in 2009 accounted for around 35% of global coal production and 50% of global coal trade, rose by about 4.5% in 2009 (Table 6.5) to $12 billion. Nonetheless, the rise in investment was much less than in 2008, Chapter 6 - Coal market outlook

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when it rose by 18%. By contrast, the top 25 oil and gas companies invested $350 billion in 2009 (see Chapter 3). Investment in the coal sector had been expected to fall significantly in 2009, with many companies announcing delayed and cancelled investments during the first half of 2009, in response to the global financial crisis. However, cash flows from higher-than-expected prices in the second-half of the year allowed many companies to maintain planned investments, even those which were forced to make production cuts and lay off workers in response to weak coal demand in OECD markets. Table 6.5 z Production, exports and investment of 25 leading coal companies Corporate base

India China United States United Kingdom China United States China Australia Germany United Kingdom Switzerland Russia China Indonesia United States Russia Poland Indonesia South Africa United States Japan Indonesia Thailand Canada United States

The 25 leading coal companies saw their production drop by close to 2% in 2009. This aggregate figure hides wide differences, from a production rise of close to 20% at PT Bumi in Indonesia to a fall of 18% at coking coal producer Teck Cominco in Canada. BHP Billiton stands out in terms of its 2009 investments. Its financial year runs to 30 June, so the $2.4 billion reported includes investment made in the second-half of 214

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2008. The figure includes a tripling of investment in Australian coking coal production, a doubling of investment in South African steam coal production and investment in a third coal terminal at Newcastle, Australia. Production at China’s three largest coal companies rose 7% in 2009, in line with a rise in national production. The future investment plans of these three companies reflect China’s ambition to continue the rapid expansion of its coal industry by opening large new mines. Taken together, the Shenhua and China National Coal Groups have announced 2010 investment plans that are 70% higher than in 2009.

Overall, the coal sector has been nimble in its response to the economic crisis that was quickly followed by a massive upturn in coal import demand from China. The investments that are being made today suggest that the industry will invest quickly enough to meet the future demand growth under the three scenarios examined in this Outlook. Cumulative coal-supply infrastructure investment in the period 2010-2035 amounts to around $720 billion in the New Policies Scenario, accounting for just over 2% of the cumulative investment in the world’s energy-supply infrastructure (see Chapter 2). Total coal sector investment, two-thirds of which is in the non-OECD countries and nearly half within the next ten years, is mainly required for mine investments, with just under 10% required for the associated infrastructure.

z World electricity demand in the New Policies Scenario is projected to grow by

2.2% per year between 2008 and 2035, from 16 819 TWh to about 30 300 TWh, slowing toward the end of the projection period as a result of increasing economic maturity and more efficient electricity use. Demand growth is led primarily by non-OECD countries, which are responsible for more than 80% of the incremental growth that occurs between 2008 and 2035. z Policies implemented to enhance energy security and to curb emissions

underpin the transition toward low-carbon technologies in the power sector. The combined share of world electricity generation from nuclear and renewable sources is projected to increase from 32% in 2008 to 45% in 2035, with generation from renewables tripling. The shift to low-carbon technologies reduces the CO2 intensity of the world power sector from 536 grammes of CO2 per kWh today to less than 360 grammes of CO2 per kWh by 2035. z Globally, coal remains the dominant source of electricity generation in 2035,

although its share declines from 41% in 2008 to 32% by 2035. In OECD countries, coal-fired generation drops by one-third between now and 2035, becoming the third-largest source of electricity generation. Growth in coal-fired generation is led by the non-OECD countries, where it doubles over the Outlook period. Gasfired generation grows in absolute terms, but maintains a stable share of world electricity generation at around 21% over the Outlook period. z In China, electricity demand triples between 2008 and 2035. Coal remains the

cornerstone of the electricity mix, although its share of generation drops from 79% in 2008 to 55% in 2035 with expected increases in the use of renewable energy, nuclear and hydropower. In absolute terms, China sees the biggest increase in generation from both renewable sources and nuclear power over the Outlook period. Between 2009 and 2025, China is projected to add generating capacity equivalent to the current total installed capacity of the United States.

z Total capacity additions, to replace obsolete capacity and to meet demand

growth, amount to more than 5 900 GW globally in the period 2009-2035; over 40% of this is installed by 2020. Cumulative global investment required in the power sector is $16.6 trillion (in year-2009 dollars) over 2010-2035. About $9.6 trillion of the total, or almost 60%, is needed to build new generating plants. Improvement and expansion of electricity networks accounts for the remainder, with cumulative investment in transmission and distribution totalling $2.2 trillion and $4.8 trillion, respectively.

Chapter 7 16- Power - Asean-4 sector country outlook profiles

217

Electricity demand The global Outlook for the power sector depends heavily on the nature and extent of policy action to reduce carbon-dioxide (CO2) emissions and enhance energy security. In all three scenarios, electricity demand increases from 2008 to 2035, driven primarily by economic and population growth. Demand growth is expected to resume, with economic recovery, in each of the scenarios, following stagnation in 2008 and 2009 as a result of the global financial crisis and subsequent recession. The Current Policies Scenario projects electricity demand to rise at an average annual growth rate of 2.5% between 2008 and 2035 (Table 7.1). Projections for electricity demand growth over the same period are lower in both the New Policies Scenario and 450 Scenario — averaging 2.2% and 1.9% per year, respectively — primarily as a result of policies aimed at improving end-use energy efficiency and curtailing CO2 emissions. Table 7.1 z Final electricity consumption by region and scenario (TWh) New Policies Scenario OECD Non-OECD World

The rate of demand growth slows over the Outlook period in each of the three scenarios, reflecting increasing economic maturity and more efficient electricity use. The New Policies Scenario projects world electricity demand rising at an annual rate of 2.7% between 2008 and 2020, and 1.8% per year over the period 2020 to 2035. Increased energy efficiency causes the rate of electricity demand growth in the OECD to slow from 0.9% between 2008 and 2020 to 0.8% per year over the period 2020 to 2035. The effect of more efficient electricity use is most notable in the non-OECD, where demand growth is 4.5% per year from 2008 to 2020, but averages 2.6% annually over the remainder of the Outlook period. More than 80% of incremental electricity demand between 2008 and 2035 comes from non-OECD countries, led by China, where, in 2035, demand is projected to equal that of the United States and European Union combined. Despite projections for strong demand growth outside the OCED, per-capita electricity consumption remains low in several regions in each of the scenarios. In the New Policies Scenario, electricity consumption per-capita doubles to 2 600 kilowatt-hours (kWh) in non-OECD countries from 2008 to 2035, whereas sub-Saharan African consumption only reaches 220 kWh per person by 2035, the lowest overall per-capita electricity consumption in any region. This is less than 3% of the average per-capita consumption projected for that same year in OECD countries. Some 585 million people in subSaharan Africa currently lack access to electricity, 79% of whom live in rural areas. The level of investment needed to achieve universal electricity access and its implications for the global energy market and CO2 emissions are discussed in Chapter 8. 218

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Electricity supply Compared with today, in the New Policies Scenario the power sector undergoes a significant transition toward low-carbon technologies between 2008 and 2035, achieving a more diverse mix. This is stimulated by several major policy actions.1 First, we assume in the New Policies Scenario that some countries (those in the OECD and in non-OECD Europe) adopt policies to curb CO2 emissions, such as cap-and-trade systems that lead to rising prices of CO2. Second, we assume that many countries, including large transition economies, implement policies designed to support renewable energy and nuclear power in order to diversify their fuel mix and enhance energy security. Global electricity generation grows by 75% over the Outlook period, rising from 20 183 terawatt-hours (TWh) in 2008 to 27 400 TWh in 2020, and to 35 300 TWh in 2035 (Figure 7.1).2 Coal continues to be the main source of electricity production, despite its share of the world mix declining from 41% in 2008 to 32% by 2035. In contrast, the share of generation from non-hydro renewable energy sources — wind, biomass, solar, geothermal and marine — increases more than five-fold, from 3% in 2008 to 16% by 2035. Electricity production from natural gas maintains a constant percentage of global generation at about 21%; similarly, the shares of hydro and nuclear also stay flat at 16% and 14%, respectively. Oil-fired generation, already a minor source of power generation in most countries, falls further to just 1% of total generation by 2035. Figure 7.1 z World electricity generation by type in the New Policies Scenario 2008

In the New Policies Scenario, coal remains the dominant fuel source in the power sector. Worldwide coal-fired generation is projected to increase from 8 273 TWh in 2008 to about 11 200 TWh by 2035, although trends differ markedly by region (Figure 7.2).3 In OECD countries, coal-fired generation drops by one-third between 1. Annex B outlines key policy assumptions by region for the three different scenarios. 2. Electricity generation includes final consumption of electricity, network losses, own use of electricity at power plants and “other energy sector”. 3. Annex A contains detailed projections of electricity generation by region and fuel, as well as other power sector trends.

Chapter 7 - Power sector outlook

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7

2008 and 2035 as the price of CO2 rises and drives up the operational costs of these plants.4 Even in the absence of government policies to curb CO2 emissions, many power companies have had difficulty building coal-fired plants, particularly in the United States, because of public opposition stemming from environmental concerns and uncertainties about future regulations. In the OECD, coal becomes the thirdlargest source of electricity generation, behind natural gas and nuclear by the end of the Outlook period. By contrast, coal-fired generation is projected to double in non-OECD countries between 2008 and 2035, where more favourable costs and domestic coal availability contribute to its role as a secure fuel to support economic growth.

The mix of world coal-fired generation technologies evolves between 2008 and 2035. Globally, generation from less efficient subcritical plants falls off dramatically, from 73% in 2008 to 48% in 2020, and to 31% by 2035. Over the medium term, these plants are displaced, primarily by supercritical plants and a rising share of combined heat and power (CHP) plants; after 2020, more advanced technologies, such as ultrasupercritical and integrated gasification combined-cycle (IGCC) plants, are more widely deployed. These technological changes steadily improve the average efficiency of the world coal-fired fleet (excluding CHP plants), which reaches above 40% by 2035, up from 35% today. Particularly striking is the progress seen in the non-OECD countries, where the average efficiency of coal-fired generation plants rises from 33% in 2008 to 40% by 2035 (Figure 7.3). Carbon capture and storage (CCS) technology is expected to be deployed on a limited scale in the New Policies Scenario, its share of total generation rising from zero today to 1.5% in 2035. Most of the projected generation from plants fitted with CCS equipment is in OECD countries, driven by government initiatives to build demonstration facilities. Stronger CO2 price signals than those in the New Policies Scenario would be needed to stimulate wider adoption of CCS technology.

4. Cost assumptions by fuel/technology and region are available at www.worldenergyoutlook.org.

Gas-fired generation rises from 4 303 TWh in 2008 to almost 7 600 TWh by 2035, with about 80% of this growth occurring in non-OECD countries. Notable growth occurs in the Middle East, where gas-fired generation doubles over the Outlook period, rising to over 1 000 TWh by 2035. Significant gas resources are available in the region, making it an attractive fuel to meet accelerating electricity needs and also to displace oilfired generation, thereby freeing up oil for other domestic uses or export. Gas-fired generation also rises considerably in non-OECD Asia, by 5.1% per year to 2035, driven by strong growth in both China and India.

In OECD countries, gas-fired generation continues to climb, though we project a slowing in the pace of growth (0.9% per year) from 2008 to 2035 compared to the rapid expansion (more than 6% per year) since 1990, led by the United States and Europe. Gas use in the power sector is sensitive to several factors, including the depth and duration of the shale-gas boom in North America and its impact on prices, the stringency and pace of actions to reduce CO2 emissions and the rate of penetration by renewable energy sources. Gas plays an important role for countries making the transition to a low-carbon power sector. Emitting approximately half the CO2 per unit of electricity produced compared with coal, gas offers a flexible source of generation that permits electricity to be quickly dispatched to meet rapid demand surges. It also provides back-up capacity to support and balance electricity markets, particularly with the increasing deployment of variable generating sources. Projected increases in world oil prices make the economics of oil-fired generation increasingly unattractive and lead to its continued decline, with output dropping from 1 104 TWh in 2008 to around 500 TWh by the end of the Outlook period. By 2035, over 40% of global oil-fired generation is projected to come from the Middle East, where many countries are likely to continue to subsidise the price of oil products for electricity generation. Chapter 7 - Power sector outlook

221

Low-carbon technologies increasingly penetrate the electricity mix in the New Policies Scenario. Renewable sources (including hydro) and nuclear power are projected to account for 45% of total global generation by 2035, up from 32% today (Figure 7.4). A marked shift occurs in OECD countries, where this share reaches 56% by 2035. Non-OECD countries also move towards low-carbon technologies in the power sector, albeit reaching a lower level because of a smaller base at the beginning of the Outlook period and less vigorous policy action to mitigate CO2 emissions. Renewable energy and nuclear power account for 39% of generation there by 2035. In absolute terms, China sees the biggest increase in generation from both renewable sources and nuclear power between 2008 and 2035, at almost 2 000 TWh and 830 TWh. Figure 7.4 z Share of nuclear and renewable energy in total electricity generation by region in the New Policies Scenario 60%

In absolute terms, global electricity generation from renewable sources triples in the New Policies Scenario, increasing from 3 772 TWh in 2008 to nearly 11 200 TWh by 2035. Rapidly expanding wind generation, rising from 219 TWh in 2008 to almost 2 900 TWh by 2035, underpins this marked growth. Electricity supply from wind grows at an average rate of 8% and 15% per year, respectively, in the OECD and the non-OECD over the period 2008-2035. Hydropower is another major source of increasing low-carbon electricity production, with generation climbing from 3 208 TWh in 2008 to about 5 500 TWh by 2035. Nearly 90% of this additional hydropower generation comes from non-OECD countries, where considerable resource potential still remains. Biomass generation increases more than five-fold over the Outlook period, rising to around 1 500 TWh in 2035. Other sources of renewable electricity supply — solar photovoltaics (PV), concentrating solar power (CSP) and marine energy — experience step changes in growth, but begin from a small base. Greater deployment of renewable energy in the New Policies Scenario, while helping to achieve a lower-carbon electricity mix, has profound implications for the operation and development of the electricity system, related to security of supply, infrastructure and costs. A detailed study of renewable energy trends in the power sector and their impacts can be found in Chapter 10. 222

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Concerns over energy security, rapidly rising demand, climate change and local pollution are driving a resurgence of interest in nuclear power in many countries. Electricity production from nuclear power is projected to climb to 4 900 TWh in 2035, up from 2 731 TWh in 2008. About 40% of this growth occurs in China alone. Rising production reflects the construction of new capacity in many other regions that are actively investing in nuclear technology or have policies in place to support nuclear power (e.g. policy targets, government loan guarantees), including the European Union, India, Japan, Russia, Korea and the United States. Further impetus for new nuclear construction comes from assumed rising prices of CO2 in OECD countries.

GW

Figure 7.5 z Nuclear capacity under construction and additions by region in the New Policies Scenario 60

Currently, most construction of nuclear capacity is being undertaken in the non-OECD countries, where 52 gigawatts (GW) of generating capacity is being built (of which 36 GW came online in 2009-2010); about 27 GW of capacity is currently under construction in mainland China (Figure 7.5) (IAEA, 2010). Given China’s plans to achieve 15% of total energy use from non-fossil-fuel sources by 2020, additional nuclear units are expected to be built between 2010 and 2020. About 16 GW of new capacity is currently under construction in OECD countries (of which 2 GW came online in 2009-2010). Of this, most is being built in Korea, Japan, France and Finland, where nuclear power development remains a core part of energy policy. Elsewhere, several projects that were previously suspended for many years have now been revived. While many OECD countries have expressed interest in and taken steps to encourage renewed development of nuclear power, new construction so far is very limited, due largely to cost uncertainties and financing limitations. Globally, the shift to low-carbon technologies in the New Policies Scenario causes the CO2 intensity of power generation to fall by 34%, from 536 grammes of CO2 per kWh today to less than 360 grammes of CO2 per kWh in 2035 (Figure 7.6). By 2035, the CO2 intensity in the European Union and Japan declines to less than half the levels of 2008, as low-carbon power generation displaces that from retired coal plants. The use of more efficient coal technologies contributes to significant reductions in power sector CO2 intensity in regions such as China and India, where coal-fired generation continues to grow. Chapter 7 - Power sector outlook

223

Grammes per kWh

Figure 7.6 z CO2 intensity of power generation by region in the New Policies Scenario China

1 000

India 800

World United States

600

Russia Japan

400

European Union

200 0 2008

2010

2015

2020

2025

2030

2035

In the New Policies Scenario, worldwide CO2 emissions from the power sector are projected to rise from 11.9 gigatonnes (Gt) in 2008 and peak at close to 14 Gt in 2030. In OECD countries, the progressive shift towards low-carbon technologies leads to declining power sector emissions from 2008 to 2035. Of total CO2 emissions from OECD countries, the share of the power sector drops from 39% in 2008 to 33% during the Outlook period. Average CO2 emissions from the power sector in non-OECD countries continue to rise through to 2035, as all forms of generation, including large amounts of coal-fired generation, increase to meet surging demand (Figure 7.7). CO2 emissions from the world power sector increase by 1.8 Gt between 2008 and 2035, slightly less than the additional CO2 emissions from the transport sector over the same period. In absolute terms, global CO2 emissions from coal fall by 4.0% between 2020 and 2035, even as coal-fired generation climbs by 5.7% during that period — reflecting the growing use of more advanced technologies.

Figure 7.7 z CO2 emissions from the power sector by region in the New Policies Scenario 12

48%

OECD

10

44%

Non-OECD

8

40%

Share of total OECD emissions (right axis)

6

36%

4

32%

2

28%

0

224

2008

2015

2020

2025

2030

2035

Share of total non-OECD emissions (right axis)

24%

World Energy Outlook 2010 - GLOBAL ENERGY TRENDS

Box 7.1 z Smart solutions to electricity system challenges The generation of and demand for electricity is constantly evolving, with challenges in all parts of the electricity system from generation, transmission and distribution, to end use. These include managing electricity production from variable sources, meeting short-duration peak loads and accommodating the growing use of plug-in hybrid and electric vehicles. Technology change and enhancements in electricity system operation are becoming essential to ensure affordable, responsive and reliable service. One solution to these challenges is to build what is often referred to as a “Smart Grid”. A Smart Grid is an electricity network that uses digital technology to monitor and manage the generation and transport of electricity from all sources in order to meet the varying electricity demands of end users as efficiently as possible. Such a grid is able to co-ordinate the needs and capabilities of all generators, grid operators, end users and electricity market stakeholders in a way that optimises asset utilisation and operation. In the process (and with appropriate market signals in place), it can minimise both costs and environmental impacts, while maintaining system reliability, resilience and stability. Smart Grids can enable wider deployment of variable technologies, such as wind and solar PV, by observing and responding to changing conditions throughout the entire electricity system and thereby maintaining a reliable service. Meeting peak demand for electricity requires a system to efficiently handle a load that may occur for only a very short duration. Smart Grids reduce peak demand by allowing customers, manually and/or automatically, to reduce and/or timeshift their consumption with little impact on operation or lifestyle. This permits minimisation of additional investment for peak plants and consequently lowers prices to end users (IEA, forthcoming).

New capacity additions, retirements and investment Total global installed power generation capacity in the New Policies Scenario is projected to increase from 4 722 GW in 2008 to about 8 600 GW by 2035. Between 2009 and 2035, total gross capacity additions amount to 5 900 GW, with more than 40% installed by 2020. This equates to average capacity additions of 213 GW per year from 2009 to 2020, rising slightly to 224 GW per year over the period 2021-2035. Nuclear power and renewable energy additions respectively account for 5% and 41% of the total between 2009 and 2020, and 7% and 53% through the remainder of the Outlook. Investment in new plants rises more quickly from 2021 to 2035, as more capitalintensive technologies are deployed and more variable resources exploited creating a need for additional generating capacity (Figure 7.8). China is projected to install the largest amount of new capacity between 2009 and 2035, accounting for more than onequarter of global additions. Chapter 7 - Power sector outlook

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7

New capacity is built to meet rising demand, projected to come mostly from non-OECD countries, and to replace retiring plants. Power plant lifetimes reflect technical limitations that arise with age and policies that influence both the economics of plants and the regulations under which they operate. Coal-fired generation has an average lifetime of 40 to 50 years before the plant becomes technically obsolete; for gas- and oil-fired generation, the average technical lifetime is about 40 years. When economically practical and technically feasible, the lifetime of some plants can be extended beyond these ranges by replacing specific parts.

1 400

2.8

1 200

2.4

1 000

2.0

800

1.6

600

1.2

Gas

400

0.8

Oil

200

0.4

0

2010-2015

2016-2020

2021-2025

2026-2030

2031-2035

Trillion dollars (2009)

GW

Figure 7.8 z World power-generation capacity additions and investment by type in the New Policies Scenario Other renewables Solar PV Wind Hydro Nuclear

Nuclear plants, originally expected to operate for 40 years, can have their lifetimes lengthened significantly by replacing certain components. Several countries are considering extending the lifetime of nuclear plants to 60 years, with some already doing so, given adherence to safety regulations. In the United States, 20-year license renewals have already been granted for most currently operating nuclear power plants to continue operation for up to 60 years and some may have their licenses extended even further (EIA, 2010). In Germany, the average lifetime of nuclear plants is assumed to be 45 years in the New Policies Scenario. Worldwide, over 400 GW of operational coal-, gas- and oil-fired capacity are more than 40 years old. With a further 585 GW between 30 and 40 years old, about one-third of the installed fossil-fuel capacity in 2008 will be approaching the end of its technical lifetime in the next 10 to 15 years. Further, the age distribution of power plants by region is striking. Plants in non-OECD countries are relatively young, as most have been built to respond to heightened demand growth during the past two decades. In contrast, plants in OECD countries are ageing, particularly coal plants that have longprovided base-load generating capacity (Figure 7.9). The ageing of installed thermal capacity could have implications, in both directions, on efforts to move to a less carbon-intensive electricity mix. Replacement with low-emissions technologies would work to facilitate this transition, but replacement with unmitigated thermal capacity (i.e. capacity that cannot be fitted for CCS) could potentially lock-in emissions for another 40 years. 226

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In the New Policies Scenario, most power plants are retired as a result of age-related technical obsolescence, but the rising price of CO2 in OECD countries also contribute to some early retirement of emissions-intensive plants. The impact of more aggressive CO2 price assumptions on the early retirement of emissions-intensive capacity is discussed further in Chapter 14, together with the associated costs. Figure 7.9 z Age profile of installed thermal and nuclear capacity by region, 2008 OECD

Total plant retirements in the New Policies Scenario amount to some 2 000 GW over the Outlook period, equal to 43% of the currently installed capacity (by 2025, more than a quarter of currently installed capacity in OECD countries is retired). Fossil-fuel plants account for two-thirds of the total capacity loss from retirements between 2009 and 2035, with about 640 GW coal, 400 GW gas and 310 GW oil going offline. Additional retirements include nuclear facilities and wind installations that reach the end of their technical lifetimes, around 2030. Nearly 35% of the new capacity additions projected over the period 2009-2035 is needed to replace existing plants (Figure 7.10), while the remainder are built to meet increasing demand. Cumulative global investment in the power sector amounts to $16.6 trillion (in year-2009 dollars) in 2010-2035 (Table 7.2). Two-thirds of the total investment comes from China, OECD Europe, the United States and India. Around $9.6 trillion of total power sector investment, or almost 60%, is invested in new generating plants (and plant refurbishments) to meet rising demand and to replace existing plants that are retired. Improvements and expansion of electricity networks account for the remainder of total power sector investment, with cumulative investment in transmission and distribution totalling $2.2 trillion and $4.8 trillion, respectively. Investment resources for transmission and distribution infrastructure can be difficult to secure given the regulatory hurdles in some countries. These are assumed to be overcome, as expanding and improving electricity networks is vital for demand management, integration of variable generation from renewable energy sources and the most efficient allocation of resources. Chapter 7 - Power sector outlook

227

European Union

331

45

2 319

95

Latin America

Brazil

76

World

114

Middle East

Africa

773

200

China

India

1 095

91

Asia

29

Caspian

161

Russia

E. Europe/Eurasia

1 542

74

Japan

Non-OECD

337

118

United States

Europe

322

262

North America

Pacific

777

OECD

Additions

170

656

7

17

8

10

22

38

74

62

13

123

232

50

59

158

191

207

424

Retirements

Capacity (GW)

685

3 655

72

149

109

129

288

1 054

1 526

143

35

252

2 165

120

211

694

498

585

1 490

New Plant

103

986

22

45

28

29

102

306

472

18

10

43

617

63

91

110

140

169

370

307

2 179

46

93

57

59

210

632

975

60

33

144

1 328

105

156

332

302

363

851

Transmission Distribution

Investment ($2009 billion)

2010-2020

469

3 354

64

138

138

144

428

760

1 494

138

30

231

2 146

111

190

498

411

520

1 208

Additions

346

1 324

12

38

45

70

58

142

244

94

18

157

554

61

98

348

273

324

770

Retirements

Capacity (GW)

1 027

5 979

126

254

235

229

679

1 168

2 347

254

37

413

3 477

211

383

1 080

873

1 039

2 502

New Plant

117

1 181

29

53

42

49

197

274

613

22

8

51

808

28

48

128

160

197

373

348

2 626

60

110

88

102

407

566

1 265

74

28

170

1 734

47

82

386

345

424

892

Transmission Distribution

Investment ($2009 billion)

2021-2035

Table 7.2 z Capacity and investment needs in power infrastructure by region in the New Policies Scenario

Figure 7.10 z World installed power-generation capacity by type in the New Policies Scenario 10 000

Capacity additions to meet new demand

8 000

Capacity additions to offset retirements

6 000

Capacity installed end-2008

4 000

Total installed capacity

2 000 0 2008

2015

2020

2025

2030

7

2035

Regional trends United States Incentives for low-carbon energy, pricing of CO2 and the availability of natural gas in the United States usher a major shift toward a lower-carbon electricity generation mix in the New Policies Scenario. The share of production from renewables, nuclear and plants fitted with CCS increases from 29% today to 35% by 2020, and then rises to 49% by 2035. The higher uptake of lower-carbon technologies post-2020 reflects a rising price for CO2 in the United States, which increases to $50 per tonne by 2035. Over the Outlook period, coal-fired generation declines by 20% (420 TWh), as ageing capacity and escalating costs lead to the retirement of more than half of currently installed coal-fired capacity (Figure 7.11). After 2020, plants using ultra-supercritical, IGCC and CCS technology account for the majority of coal-fired capacity additions. New plants fitted with CCS are initially installed as demonstration facilities, but a climbing price for CO2 also contribute to their reaching a 3.6% share of generation by 2035.

GW

Figure 7.11 z Power-generation capacity by type in the United States in the New Policies Scenario 1 400

Renewable energy sources, nuclear and gas-fired generation are projected to replace generation from retired coal-fired power plants and to meet growing electricity demand in the United States. Gas-fired generation grows by about 190 TWh between 2008 and 2035 (Figure 7.14a). With the shale gas boom, and increasing gas production in North America, gas is an available resource that can enhance reliability in the power sector as more variable generation, such as wind and solar PV, is integrated. Utilisation rates for gas-fired capacity are projected to increase from 25% in 2008 to 30% in 2035. Power generation from renewables triples from 2008 to 2035, driven partly by the assumed adoption of a federal renewable electricity standard in the New Policies Scenario. Wind power accounts for the largest additional generation, at 460 TWh. More than half of new capacity additions in the power sector over the Outlook period rely on renewable energy sources. After 2020, additional nuclear capacity is expected to come online, at an average rate of 1.2 GW per year, supported by loan guarantees. Few nuclear plant retirements are projected, as it is assumed most plants are granted licenses to operate for up to 80 years (most plants currently have licenses that allow operation for up to 60 years). New power plants of all types require investment of $1.4 trillion over the Outlook period. Nearly two-thirds of this investment comes after 2020, when a surge in deployment of low-carbon, capital-intensive technologies is anticipated. Annual CO2 emissions from the power sector are projected to be reduced by 0.6 Gt, or more than one-quarter, compared to today.

In the European Union, the price for CO2 in the New Policies Scenario is instituted earlier and is initially higher than in other OECD countries. It rises to $38 per tonne by 2020 and $50 per tonne by 2035. This, in combination with binding targets for renewable energy consumption, accelerates renewable electricity generation over the Outlook period. Coal-fired generation declines steeply, by 550 TWh between 2008 and 2035, with its share of the mix falling from 28% to 10% (Figure 7.14b). About 160 GW of coal-fired capacity (78% of currently installed capacity) is retired between 2008 and 2035, partially offset by almost 70 GW of non-subcritical and CHP coal-fired plants that come online during that period. Gas-fired power generation maintains a steady share at one-quarter of total generation mix between 2008 and 2035. Surging generation from renewable energy sources in the European Union causes the share of electricity generation from renewables (including hydro) to climb from 17% in 2008 to 30% by 2020 and 41% by 2035 (Figure 7.12). Over the Outlook period, wind power accounts for more than 40% of cumulative capacity additions and supplies more incremental electricity generation than any other source. Electricity generation from nuclear power remains relatively flat in the European Union, as countries add only enough new capacity to replace plants reaching the end of their operating lifetimes (45 to 55 years). Investment in new plants of all types totals $1.7 trillion between 2010 and 2035, with more than 70% destined for renewable energy. Gradual decarbonisation of the power sector causes CO2 emissions to fall from 1.4 Gt in 2008 to 0.8 Gt by 2035. 230

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35 336 TWh

32%

5 169 TWh

33%

Coal Oil

36%

69%

2008

52%

2035

3 106 TWh

India

79%

55% 9 594 TWh

China

3 495 TWh

1 416 TWh

830 TWh

1 038 TWh

Hydro Other renewables

1 613 TWh

63%

Middle East

3 938 TWh

771 TWh

58%

Gas Nuclear

3 339 TWh

31%

48%

Note: For each region, the largest source of electricity generation in 2008 and 2035 is denoted by its percentage share of the overall mix.

20 183 TWh

41%

World

4 343 TWh

49%

United States

28%

European Union

Russia

Figure 7.12 z Electricity generation by fuel and region in the New Policies Scenario

Japan In Japan, the rising price of CO2 in the power sector in the New Policies Scenario increases operational costs for coal-fired plants and encourages more generation from nuclear and renewables, whose combined share of total generation climbs from 34% in 2008 to 62% in 2035. Coal-fired generation in Japan drops by almost two-thirds between 2008 and 2035, its share of overall generation declining from 27% to 9% during that period (Figure 7.14c). Electricity from oil-fired plants also declines steeply over the projection period, as rising oil prices discourage their use. Lost output from coal- and oil-fired plants is partially offset by more gas-fired generation in the medium term, but this too starts to decline with a higher price for CO2 after 2020. Installed nuclear capacity in Japan rises from 48 GW in 2008 to around 70 GW in 2035, the share of nuclear power in electricity generation rising from 24% to 42% over the Outlook period. Reaching this level of nuclear capacity requires investment of about $110 billion, or one-third of the total spent by Japan on new power plants, between 2008 and 2035. The shares of wind and solar PV in the electricity mix rise to 4.5% and 2.3% by 2035. This is primarily the result of an increasing price for CO2 and incentives in the case of solar PV. The move toward a less carbon-intensive power sector results in CO2 emissions declining 46% by 2035, or 0.2 Gt, compared with today.

China Electricity demand in China rises briskly in the New Policies Scenario, at an annual rate of 7.7% through 2015, and then averages 2.8% per year over the remainder of the Outlook period as the pace of economic growth slows and electricity use becomes more efficient. Overall, demand is projected to triple between 2008 and 2035, with China overtaking the United States in 2012 as the largest global consumer of electricity. Nonetheless, per-capita electricity consumption in China rises to only 65% of the average in OECD countries by 2035. Coal remains the cornerstone of the electricity mix during the Outlook period, although its share of generation drops from 79% in 2008 to 55% in 2035. Annual coal-fired electricity generation increases 2 500 TWh between 2008 and 2035, with almost 60% of the rise occurring by 2015 (Figure 7.14d). By 2035, gasfired generation increases 20 times over current levels, supplying 9% of total electricity generation.

The share of low-carbon power generation in China — including nuclear, CCS-fitted plants, hydro and other renewables — doubles from 2008 to 2035, when it reaches 38% of total generation. This transition aims to achieve China’s targets for renewables and nuclear by 2020 to diversify the energy mix away from fossil fuels and reduce local pollution. Electricity generation from hydro and wind both increase by more than 700 TWh to provide 14% and 7% of the electricity mix by the end of the Outlook period. With many nuclear plants already under construction, a surge of new generating capacity is expected by 2020, increasing annual generation by 800 TWh between 2008 and 2035. The capacity additions required to meet China’s electricity needs over the period 2009-2035 are staggering: between 2009 and 2025 China will have added new capacity equivalent to the current installed capacity of the United States (Figure 7.13). A total 232

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of $2.2 trillion in investment will be necessary to build new plants over the Outlook period, with about half required between 2010 and 2020. Of total investment in new plants from 2010 to 2035, 62% goes to renewable energy (including hydro), 20% to coal-fired facilities and 14% to nuclear power. Although the CO2 intensity of power generation declines by 38% over the Outlook period, overall CO2 emissions from the power sector increase from 3.1 Gt in 2008 to 5.1 Gt by 2035.

GW

Figure 7.13 z Cumulative capacity additions in China in the New Policies Scenario from 2009 compared with the 2008 installed capacity of selected countries 1 800

In the New Policies Scenario the combination of rising population and economic growth in India leads to electricity demand rising almost four-fold from 2008 to 2035, making it the third-largest consumer of electricity at the end of the Outlook period, behind China and the United States. Demand steadily increases through the period, with onehalf of incremental growth coming from the industrial sector. Coal continues to be the main source of electricity generation, although its share declines from 69% in 2008 to 52% in 2035. In absolute terms, annual coal generation increases more than generation from any other fuel, by more than 1 000 TWh between 2008 and 2035 (Figure 7.14e). Almost all new coal-fired capacity additions between 2008 and 2020 use subcritical and supercritical technology; after this time, more advanced coal technologies begin to enter the mix. This realises a projected rise in average coal efficiency from 34% in 2020 to 40% in 2035. Gas-fired generation also increases considerably, from 82 TWh in 2008 to about 450 TWh by 2035, with its share of total generation increasing from 10% to 14%. Total electricity generation from low-carbon energy sources in India, including nuclear, increases seven-fold from 2008 to 2035, with their share of total generation rising from 17% to 33%. New hydropower projects are expected to result in a 290 TWh increase in annual generation between 2008 and 2035. The share of nuclear generation in the electricity mix rises from 2% to 6% as 25 GW of new capacity is installed. Of non-hydro renewable energy sources, wind generation grows most in Chapter 7 - Power sector outlook

233

TWh

Figure 7.14 z Change in electricity generation relative to 2008 by type for selected countries in the New Policies Scenario a) United States

absolute terms, from 14 TWh in 2008 to 190 TWh in 2035. The greatest level of investment in new plants will go to coal installations, which account for almost 40% of the $1 trillion required from 2010 to 2035. The projected expansion of electricity generation from fossil-fuels causes CO2 emissions from India’s power sector to rise from 0.8 Gt in 2008 to 1.6 Gt by 2035.

Russia In Russia, electricity generation from gas-fired plants rises through 2025 in the New Policies Scenario, declining thereafter as new nuclear and renewable capacity is brought online (Figure 7.14f). Gas-fired electricity accounted for 48% of total generation in 2008. This drops to 36% by 2035. The share of coal-fired generation in the electricity mix also falls, from 19% in 2008 to 16% by 2035. More electricity generation from low-carbon sources — principally nuclear, hydro and wind — enters the mix, their combined share of generation reaching almost half of the total by 2035. Electricity generation from nuclear power rises more than any other source from 2008 to 2035 with an increase of 120 TWh. This is the combined result of nuclear capacity additions and projected improvements in plant operation which raise the average capacity factor of nuclear plants from 80% in 2008 to 85% by 2035. Over the Outlook period, electricity output from hydro climbs by 90 TWh and from wind by 70 TWh. Total investment required for new generating capacity from 2010 to 2035 amounts to $0.4 trillion, with one-third going to renewable energy (including hydro), 28% to nuclear power and 23% to gas. The introduction of low-carbon technologies slightly lowers power sector CO2 emissions, from 0.9 Gt today to 0.8 Gt in 2035.

In the Middle East, strong economic and population growth drive a doubling in electricity demand between 2008 and 2035 in the New Policies Scenario. As an abundant resource in the region, gas is projected to remain the dominant fuel in the power sector, with its share of total generation increasing from 58% in 2008 to 63% by 2035. In absolute terms, gas generation rises by 580 TWh over the Outlook period, accounting for almost 70% of growth in supply. Due to rising prices for oil, and therefore the rising value of oil exports, the share of oil-fired generation in the electricity mix is projected to decline from 36% in 2008 to 13% by 2035. Renewable energy sees strong growth in the power sector of Middle Eastern countries, with generation from wind, CSP and solar PV rising noticeably over the Outlook period. As a share of electricity generation, renewable energy is projected to increase from 1% today to 16% by 2035. Nearly 280 GW of new generating capacity is added between 2008 and 2035, one-third of which is from the installation of combined water desalinisation and power plants. About 3 GW of nuclear capacity is installed in countries that have existing development plans and available capital. Total expenditure on new generating capacity in the Middle East between 2010 and 2035 amounts to $0.4 trillion, with about one-third spent on gas-fired plants. The large increase in fossil-fuel based generation leads to rising CO2 emissions from the power sector, which increase from 0.5 Gt today to 0.7 Gt by 2035.

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CHAPTER 8

ENERGY POVERTY Can we make modern energy access universal? H

I

G

H

L

I

G

H

T

S

z We assess two indicators of energy poverty at the household level: the lack

of access to electricity and the reliance on the traditional use of biomass for cooking. In sub-Saharan Africa the electrification rate is 31% and the share of people relying on biomass 80%: this is where the greatest challenge lies. z Today, there are 1.4 billion people in the world that lack access to electricity,

some 85% of them in rural areas. Without additional dedicated policies, by 2030 the number of people drops, but only to 1.2 billion. Some 15% of the world’s population still lack access, the majority in sub-Saharan Africa. z The number of people relying on biomass is projected to rise from 2.7 billion

today to 2.8 billion in 2030. Using WHO estimates, linked to our projections of biomass use, it is estimated that household air pollution from the use of biomass in inefficient stoves would lead to over 1.5 million premature deaths per year (over 4 000 per day) in 2030, greater than estimates for premature deaths from malaria, tuberculosis or HIV/AIDS. z Addressing these inequities depends upon international recognition that the

projected situation is intolerable, a commitment to effect the necessary change, and setting targets and indicators to monitor progress. A new financial, institutional and technological framework is required, as is capacity building in order to dramatically scale up access to modern energy services at the local and regional levels. We provide a monitoring tool, the EDI, that ranks developing countries in their progress towards modern energy access. z The first UN MDG of eradicating extreme poverty and hunger by 2015 will not be

achieved unless substantial progress is made to improve energy access. To meet the goal, an additional 395 million people need to be provided with electricity and an additional 1 billion provided with access to clean cooking facilities. This will require annual investment in 2010-2015 of $41 billion, or only 0.06% of global GDP.

z To meet the more ambitious target of achieving universal access to modern

energy services by 2030, additional investment of $756 billion in 2010-2030, or $36 billion per year, is required. This is less than 3% of the global energy investment projected in the New Policies Scenario to 2030. The resulting increase in energy demand and CO2 emissions would be modest. In 2030, global oil demand would have risen less than 1% and CO2 emissions would be only 0.8% higher, compared with the New Policies Scenario.

Chapter 16 8 - Energy - Asean-4 poverty country profiles

237

Introduction Making energy supply secure and curbing energy’s contribution to climate change are often referred to as the two over-riding challenges faced by the energy sector on the road to a sustainable future. This chapter highlights another key strategic challenge for the energy sector, one that requires immediate and focused attention by governments and the international community. It is the alarming fact that today billions of people lack access to the most basic energy services, electricity and clean cooking facilities, and, worse, this situation is set to change very little over the next 20 years, actually deteriorating in some respects. This is shameful and unacceptable. Lack of access to modern energy services1 is a serious hindrance to economic and social development and must be overcome if the UN Millennium Development Goals (MDGs) are to be achieved.2 This chapter which presents the results of joint work with the United Nations Development Programme (UNDP) and the United Nations Industrial Development Organization (UNIDO) investigates the energy-access challenge. We estimate the number of people who need to gain access to modern energy services and the scale of the investments required, both in the period to 2015 and over the longer term, in order to achieve the proposed goal of universal access to modern energy services by 2030 (AGECC, 2010).3 We also discuss the implications of universal access to modern energy services for the global energy market and for the environment and health. The chapter includes an Energy Development Index and a discussion of the path to improving access to modern energy services, as well as financing mechanisms and the implications for government policy in developing countries. The focus of this chapter is on expanding access to modern energy services at the household level. This is but one aspect of overcoming energy poverty. Other aspects include providing access to electricity and mechanical power for income-generating activities, the reliability of the supply to households and to the wider economy and the affordability of energy expenditure at the household level. These other aspects of energy poverty are areas for future research in the World Energy Outlook.

The numbers related to household access to energy are striking. We estimate that 1.4 billion people — over 20% of the global population — lack access to electricity and that 2.7 billion people — some 40% of the global population — rely on the traditional 1. Access to modern energy services is defined here as household access to electricity and clean cooking facilities (i.e. clean cooking fuels and stoves, advanced biomass cookstoves and biogas systems). 2. In September 2000, at United Nations Headquarters in New York, world leaders adopted the United Nations Millennium Declaration, committing their nations to a global partnership to eradicate extreme poverty and setting out eight goals — with a deadline of 2015 — that have become known as the Millennium Development Goals (www.un.org/millenniumgoals). The MDGs do not include specific targets in relation to access to electricity or to clean cooking facilities, but universal access to both is necessary for the realisation of the Goals (see Box 8.2). 3. The Advisory Group on Energy and Climate Change (AGECC), a committee set up by UN Secretary-General Ban Ki-moon, is charged with assessing the global energy situation and incorporating this into international climate change talks. It has proposed a goal to achieve universal access to modern energy services by 2030. Because of this, the time frame for the projections in this chapter is to 2030.

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use of biomass for cooking (Table 8.1).4 Worse, our projections suggest that the problem will persist and even deepen in the longer term: in the New Policies Scenario, 1.2 billion people still lack access to electricity in 2030, 87% of them living in rural areas (Figure 8.1). Most of these people will be living in sub-Saharan Africa, India and other developing Asian countries (excluding China). In the same scenario, the number of people relying on the traditional use of biomass for cooking rises to 2.8 billion in 2030, 82% of them in rural areas.

Table 8.1 z Number of people without access to electricity and relying on the traditional use of biomass, 2009 (million) Number of people lacking access to electricity

Number of people relying on the traditional use of biomass for cooking

Africa

587

Sub-Saharan Africa

585

653

Developing Asia

799

1 937

China

8

423

India

404

855

Other Asia

387

659

Latin America

657

31

85

Developing countries*

1 438

2 679

World**

1 441

2 679

8

*Includes Middle East countries. **Includes OECD and transition economies. Note: The World Energy Outlook maintains a database on electricity access and reliance on the traditional use of biomass, which is updated annually. Further details of the IEA’s energy poverty analysis are available at www.worldenergyoutlook.org/development.asp. Source: IEA databases and analysis.

The greatest challenge is in sub-Saharan Africa, where today only 31% of the population has access to electricity, the lowest level in the world. If South Africa is excluded, the share declines further, to 28%. Electricity consumption in sub-Saharan Africa, excluding South Africa, is roughly equivalent to consumption in New York. In other words, the 19.5 million inhabitants of New York consume in a year roughly the same quantity of electricity, 40 terawatt-hours (TWh), as the 791 million people of sub-Saharan Africa (Figure 8.2).

4. The traditional use of biomass refers to the basic technology used, such as a three-stone fire or an inefficient cookstove, and not the resource itself. The number of people relying on the traditional use of biomass is based on survey and national data sources, and refers to those households where biomass is the primary fuel for cooking. While the analysis in this chapter focuses on biomass, it is important to note that, in addition to the number of people relying on biomass for cooking, some 0.4 billion people, mostly in China, rely on coal for cooking. This is a highly polluting fuel when used in traditional stoves and has serious health implications.

Chapter 8 - Energy poverty

239

Note: not to scale

2

8

465

108 544

The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA.

27

4

Latin America

120

Sub-Saharan Africa 381

23

India

328

59

212

40

Other developing Asia

2030 Urban

2009 Rural

1 052

161

214 1 227

1 213

1 441

World population without access to electricity

281

12

8

China

Figure 8.1 z Number of people without access to electricity in rural and urban areas in the New Policies Scenario (million)

Figure 8.2 z Residential electricity consumption in New York and sub-Saharan Africa

New York 40 TWh

pita per ca 2 050 kWh

52 k

Population: 19.5 million

Wh per capit a

8

Population: 791 million The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA.

Energy and development Access to modern forms of energy is essential for the provision of clean water, sanitation and healthcare, and provides great benefits to development through the provision of reliable and efficient lighting, heating, cooking, mechanical power, transport and telecommunication services.5 The international community has long been aware of the close correlation between income levels and access to modern energy: not surprisingly, countries with a large proportion of the population living on an income of less than $2 per day tend to have low electrification rates and a high proportion of the population relying on traditional biomass (Figures 8.3 and 8.4).

As incomes increase, access to electricity rises at a faster rate than access to modern cooking fuels, largely because governments give higher priority to electrification, though access to both electricity and clean cooking facilities is essential to success in eradicating the worst effects of poverty and putting poor communities on the path to development. 5. Household income is the central factor linking achievement of the MDGs and access to modern energy services. Causality is mainly from income to energy access: although improved access to energy can help raise incomes. Moreover, access to electricity is not only a result of economic growth but electricity access also contributes actively to economic growth (Birol, 2007). In this regard, reliability, and not just access, is very important to sustainable economic growth.

*Modern fuels exclude traditional biomass. Note: The size of the bubble is proportional to population. Sources: Consumption of modern fuels: IEA data and analysis; and poverty rate: http://data.worldbank.org/ indicator/SI.POV.2DAY.

The adverse consequences of the use of traditional forms of energy for health, economic development and the environment are well illustrated by the example of the use of traditional biomass for cooking (Hutton, Rehfuess and Tediosi, 2007; UNEP, 242

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2003; and IEA, 2006). Currently, devices for cooking with biomass are mostly threestone fires,6 traditional mud stoves or metal, cement and pottery or brick stoves, with no operating chimneys or hoods (Box 8.1). As a consequence of the pollutants emitted by these devices, pollution levels inside households cooking with biomass are often many times higher than typical outdoor levels, even those in highly polluted cities. The World Health Organization (WHO) estimates that more than 1.45 million people die prematurely each year from household air pollution due to inefficient biomass combustion (thus excluding premature deaths from cooking with coal). A significant proportion of these are young children, who spend many hours each day breathing smoke pollution from the cookstove. Today, the number of premature deaths from household air pollution is greater than the number of premature deaths from malaria or tuberculosis (Figure 8.5). Using World Health Organization projections for premature deaths to 2030,7 the annual number of premature deaths over the projection period from the indoor use of biomass is expected to increase in the New Policies Scenario, unless there is targeted action to deal with the problem. By 2030 over 1.5 million people would die every year due to the effects of breathing smoke from poorly-combusted biomass fuels. This is more than 4 000 people per day. By contrast, the World Health Organization expects the number of premature deaths from malaria, tuberculosis or HIV/AIDS to decline over the same period.

In developing regions in which households are heavily reliant on biomass, women and children are generally responsible for fuel collection, a time-consuming and exhausting task. Women can suffer serious long-term physical damage from strenuous work without sufficient recuperation. This risk, as well as the hazards of falls, snake bites 6. A three-stone fire uses three stones to support the pot and firewood is placed underneath. 7. The estimations for premature deaths are based on Mathers and Loncar (2006); WHO (2008); Smith et al., (2004); and WHO (2004).

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8

or human assault, rises steeply the further from home women have to walk. Inefficient and unsustainable cooking practices also have serious implications for the environment, such as land degradation and contributing to local and regional air pollution.8 In cities where households are primarily reliant on wood or wood-based charcoal for cooking, there is local deforestation in the surrounding areas. Box 8.1 z Cooking and lighting in the poorest households The world’s poorest households tend to use three-stone fires for cooking. The high moisture content of the biomass resources used and the low efficiency of the combustion process produce dangerous levels of smoke, particularly if food is cooked indoors. The efficiency of biomass can be increased through provision of improved stoves and enhanced ventilation. Adding chimneys to stoves with low combustion efficiency can be a useful improvement, as long as the chimney is kept clean and maintained. However, often there is some leakage into the room and the smoke is merely vented outside the house and will, in part, re-enter the dwelling, so this option is not as effective as a change to clean fuels or advanced biomass stoves. Experience suggests that in order for biomass gasifiers for cooking to consistently achieve emissions close to those of LPG, the stove requires assisted air flow by use of a fan. Ventilation of the home (i.e. eaves spaces and larger, open windows and doors) can contribute to reducing household air pollution but alone is unlikely to make a substantial difference if there is a highly polluting indoor source. Lighting in low-income households in developing countries is generally provided by candles or kerosene/diesel lanterns. Candles and low-efficiency lanterns emit smoke. Kerosene lamps produce better light, but they are uncomfortably hot in a tropical climate and they can be difficult to light. Use of kerosene also imposes health risks, through fires and children drinking fuel stored in soft drink bottles, and there is emerging evidence of links with tuberculosis and cancer. Switching to electricity eliminates these risks and increases efficiency. A paraffin wax candle has an intensity (in lumens) of 1 and an efficiency (lumens per watt) of .01, while a 15 watt fluorescent bulb has an intensity of 600 and efficiency of 40.9 There has been much recent success in the dissemination of compact fluorescent light bulbs (CFLs) in many developing countries. High-quality CFLs are four to five times more efficient than incandescent bulbs and last much longer. Large-scale deployment of CFLs can help reduce peak electricity needs and ameliorate infrastructure shortages.

8. Scientists have recently reported that soot, or black carbon, such as that emitted from the burning of biomass in inefficient stoves, plays a large role in global and regional warming. Black carbon forms during incomplete combustion, and is emitted by a wide range of sources, including diesel engines, coal-fired power plants and residential cookstoves. Warming driven by black carbon appears to be especially amplified in the high country of Asia’s Tibetan Plateau, where summer melt-water provides water to more than one billion people. Glaciers on the plateau have declined by about 20% since the 1960s (Luoma, 2010). 9. Light intensity, or illuminating power of a light source, in any one direction is commonly defined as “candela”, which can be thought of as “candle-power”; i.e. the output from a standard paraffin wax candle. The rate at which light is emitted is measured in lumens, which are defined as the rate of flow of light from a light source of one candela through a solid angle of one steradian, the Standard International unit of solid angular measure.

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Effective environmental management cannot be excluded from energy and development concerns. Preventing irreversible damage to the global climate will require decarbonisation of the world’s energy system (see Chapter 13). For developing countries, however, difficult choices have to be made in allocating scarce resources among pressing development needs, and climate change is often viewed as a longerterm concern that must be traded off against short-term priorities. While the poorest developing countries are not major contributors to climate change, their populations suffer acutely from its effects. For oil net importing developing countries in particular, rising and volatile prices have amplified the challenge of expanding energy access and put an extra burden on fiscal budgets. In a high-energy price and climate-conscious world, it makes sense for governments tackling the energy poverty challenge to choose a course consistent with long-term sustainable development goals, rather than choose the energy technologies and mix used by OECD countries in the 1950s and 1960s. The World Resource Institute has defined Sustainable Development Policies and Measures (SD-PAMs) which offer an opportunity for developing countries to reduce emissions through tailored, development-focused policies, that are guided by domestic priorities.10 Policies in the energy sector that countries would be likely to pursue as SD-PAMs include measures to promote energy efficiency, the broader use of renewable energy sources and steps to reduce energy subsidies while safeguarding the welfare of poor households.

Energy and the Millennium Development Goals The eight Millennium Development Goals (MDGs), adopted in 2000, were designed to eradicate extreme poverty and hunger by 2015. Energy can contribute to the achievement of many of these goals (Box 8.2). But the MDGs contain no goal specifically related to energy and there are no targets or indicators associated with the MDGs that would enable governments and the international community to monitor progress towards universal access.11 The UN Advisory Group on Energy and Climate Change has called for adoption of the goal of universal access to modern energy services by 2030. Box 8.2 z The importance of modern energy in achieving the MDGs

Goal 1: Eradicate extreme poverty and hunger. Access to modern energy facilitates economic development by providing more efficient and healthier means to undertake basic household tasks and means to undertake productive activities more generally, often more cheaply than by using the inefficient substitutes, such as candles and batteries. Modern energy can power water pumping, providing drinking water and increasing agricultural yields through the use of machinery and irrigation.

10. www.wri.org/project/sd-pams. 11. The only indicator related to energy is for CO2 emissions: total, per capita and per $1 GDP (PPP) under Goal 7. At the 12th International Energy Forum (IEF) Ministerial in Cancun, Mexico, in March 2010, the IEF called for the international community to set up a ninth goal, specifically related to energy, to consolidate the evident link between modern energy services and achievement of the MDGs.

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8

Goal 2: Achieve universal primary education. In impoverished communities children commonly spend significant time gathering fuelwood, fetching water and cooking. Access to improved cooking fuels or technologies facilitates school attendance. Electricity is important for education because it facilitates communication, particularly through information technology, but also by the provision of such basic needs as lighting. Goal 3: Promote gender equality and empower women. Improved access to electricity and modern fuels reduces the physical burden associated with carrying wood and frees up valuable time, especially for women, widening their employment opportunities. In addition, street-lighting improves the safety of women and girls at night, allowing them to attend night schools and participate in community activities. Goals 4, 5, and 6: Reduce child mortality; Improve maternal health; and Combat HIV/AIDS, malaria and other diseases. Most staple foods require cooking: reducing household air pollution through improved cooking fuels and stoves decreases the risk of respiratory infections, chronic obstructive lung disease and lung cancer (when coal is used). Improved access to energy allows households to boil water, thus reducing the incidence of waterborne diseases. Improved access advances communication and transport services, which are critical for emergency health care. Electricity and modern energy services support the functioning of health clinics and hospitals. Goal 7: Ensure environmental sustainability. Modern cooking fuels and more efficient cookstoves can relieve pressures on the environment caused by the unsustainable use of biomass. The promotion of low-carbon renewable energy is congruent with the protection of the environment locally and globally, whereas the unsustainable exploitation of fuelwood causes local deforestation, soil degradation and erosion. Using cleaner energy also reduces greenhouse-gas emissions and global warming. Goal 8: Develop a global partnership for development. Electricity is necessary to power information and communications technology applications. Source: Adapted from UN-Energy, 2005.

The Universal Modern Energy Access Case To illustrate what would be required to achieve universal access to modern energy services, we have developed the Universal Modern Energy Access Case. This case quantifies the number of people who need to gain access to modern energy services and the scale of the investments required by 2030. It includes interim targets to 2015, related to the achievement of the Millennium Development Goals. 246

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The energy targets adopted to 2015 are consistent with the achievement of MDG 1 — eradicating extreme poverty and hunger. We interpret this, in this context, as meaning that no more than one billion people should be without access to electricity by that date, and no more than 1.7 billion should still be using traditional biomass for cooking on open fires or primitive stoves (Table 8.2). The relationship between poverty and modern energy access has been derived from a cross-country analysis covering 100 countries and the projections are based on regression analyses, which are applied to each region.

Note: Liquefied petroleum gas (LPG) stoves are used as a proxy for modern cooking stoves, also including kerosene, biofuels, gas and electric stoves. Advanced biomass cookstoves are biomass gasifier-operated cooking stoves which run on solid biomass, such as wood chips and briquettes. Biogas systems include biogasfired stoves.

Our analysis shows that, compared to the projections in the New Policies Scenario, in order to achieve the stated interim goals by 2015 an additional 395 million people need to be provided with electricity and an additional 1 billion provided with access to clean cooking facilities. These are demanding targets; in the New Policies Scenario they are not achieved even in 2030 (Figure 8.6). For 2030, the Universal Modern Energy Access Case calculates what would be involved in achieving the more ambitious goal of universal access to modern energy services. Beyond the achievement of the interim 2015 target, this translates into the provision of electricity to an additional 800 million people and giving an additional 1.7 billion people access to clean cooking fuels in 2016-2030. The investment implications are examined more closely below. But, in brief, bringing electricity to the 1.2 billion people who would otherwise not have access to it by 2030 would require additional cumulative investment, beyond that in the New Policies Scenario, of $700 billion in 2010-2030, or $33 billion per year. In addition, in order to achieve universal access to clean cooking facilities for some 2.8 billion people, additional cumulative investment of some $56 billion would be required in 2010-2030, or $2.6 billion per year. Thus $756 billion additional investment is required to achieve universal access to electricity and clean cooking facilities by 2030. Chapter 8 - Energy poverty

247

Access to clean cooking facilities

Figure 8.6 z Access to modern energy services in the New Policies Scenario and Universal Modern Energy Access Case 100% 2030 Universal Modern Energy Access Case

90% 80% 2015 Universal Modern Energy Access Case

70% 60%

2030 New Policies Scenario

2015 New Policies Scenario

Today

50% 40% 30%

75%

80%

85%

90%

95% 100% Electrification rate

This sum is put in perspective when seen in relation to the projected global energy investment of over $26 trillion in 2010-2030 in the New Policies Scenario: it is less than 3% of global energy investment. Universal access to modern energy services would have little impact on energy demand, production or CO2 emissions. In 2030, global electricity generation would be 2.9% higher, oil demand would have risen less than 1% and CO2 emissions would be 0.8% higher, compared to the New Policies Scenario.

Access to electricity Today, more than 1.4 billion people worldwide lack access to electricity: 585 million people in sub-Saharan Africa (including over 76 million in Nigeria and some 69 million in Ethiopia) and most of the rest in developing Asia (including 400 million in India and 96 million in Bangladesh). Some 85% of those without access live in rural areas.

In the New Policies Scenario, the number of people lacking access to electricity in 2015 is still around 1.4 billion, practically unchanged from today (Figure 8.7). To achieve the targets we have defined in the Universal Modern Energy Access Case to be consistent with the achievement of the first MDG of eradicating extreme poverty by 2015, the number of people without electricity in 2015 would need to be about 395 million less than this, i.e. about 1 billion. The global electrification rate would then be 86%, five percentage points higher than the electrification rate achieved in the New Policies Scenario in 2015. Although electrification will progress over the period to 2030, the need will grow as the population increases.12 In the New Policies Scenario, without additional, dedicated policies, there are still 1.2 billion people lacking access in 2030 (Table 8.3). 12. Electricity access occurs at a much faster rate in urban areas, as companies are often required to provide electricity service and it is more profitable. Most of the increase in the number of people with access over the projection period is in urban areas in the New Policies Scenario.

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The electrification rate in developing countries increases from 73% in 2009 to 81% in 2030. China is projected to achieve universal electrification soon after 2015. In developing Asian countries apart from China and India, the electrification rate rises to 82%, but 252 million people still lack access in 2030. Electricity access in Latin America is nearly universal by 2030. In sub-Saharan Africa, the absolute number of people lacking access is projected to continue to rise, despite an increase in the electrification rate; by 2030, the region accounts for 54% of the world total, compared with 41% in 2009.

Population without electricity (million)

Figure 8.7 z Implication of eradicating extreme poverty on number of people without access to electricity by 2015 1 500 Population to be provided with electricity access

1 200 900

8

600 300 0

2009

2015 New Policies Scenario

2015 Universal Modern Energy Access Case

To assess the extent of the additional generating capacity required to achieve universal access, we have made assumptions about minimum levels of consumption at both the rural and urban level: rural households are assumed to consume at least 250 kilowatthours (kWh) per year and urban households 500 kWh per year. In rural areas, this level of consumption could provide for the use, for example, of a floor fan, two compact fluorescent light bulbs and a radio for about five hours per day. In urban areas, consumption could also include a television and another appliance, such as an efficient refrigerator or a computer. Consumption is assumed to rise every year until reaching the average national level.

This amounts to total incremental electricity output by 2030 of around 950 TWh. This additional electricity generation represents some 2.9% of the nearly 33 000 TWh generated worldwide in 2030 in the New Policies Scenario. To generate this additional electricity output would require generating capacity of 250 GW. Various options for supplying this electricity need to be considered, including on-grid, mini-grid13 and isolated off-grid (Table 8.4). Grid extension will contribute part of the solution, but decentralised options have an important role to play when grid extension is too expensive and will provide the bulk of the additional connections over the projection period (see also, Box 8.3, Figure 8.12 and the associated text). 13. Mini-grids are village- and district-level networks with loads of up to 500 kilowatts.

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Table 8.3 z Number of people without access to electricity and electrification rates by region in the New Policies Scenario (million) 2009 Rural

Achieving universal electricity access would have a modest impact on energy-related CO2 emissions. Compared with the New Policies Scenario, global energy-related CO2 emissions in the Universal Modern Energy Access Case increase by just 0.8% by 2030, or around 2% of current OECD emissions. If the generation fuel mix to supply the additional demand in the Universal Modern Energy Access Case was the same as that projected in the 450 Scenario, the increase in energy-related global CO2 emissions would be a mere 0.6% (Figure 8.8).

8 Access to clean cooking facilities There are currently about 2.7 billion people in developing countries who rely for cooking primarily on biomass including wood, charcoal, tree leaves, crop residues and animal dung used in inefficient devices.14 This number is higher than estimates in previous editions of the World Energy Outlook, due to population growth, rising liquid fuel costs and the global economic recession (which have driven a number of people back to using traditional biomass).15 About 82% of those relying on traditional biomass live in rural areas, although in sub-Saharan Africa, nearly 60% of people living in urban areas also use biomass for cooking. The share of the population relying on the traditional use of biomass is highest in sub-Saharan Africa and India (Figure 8.9).

In the New Policies Scenario, the number of people relying on the traditional use of biomass for cooking increases from just under 2.7 billion in 2009 to about 2.8 billion in 2015. To achieve the Millennium Development Goals would necessitate a substantial reduction. In a similar manner to that used to define targets for universal electricity access, we have defined targets for access to clean cooking facilities, related to the MDG for poverty reduction (see Table 8.2). In the Universal Modern Energy Access Case, eradicating extreme poverty by 2015 would mean reducing the number of people still using traditional biomass to around 1.7 billion by 2015, that is, beyond the projections in the New Policies Scenario, 1 billion more people would need to gain access to clean cooking facilities, including LPG stoves, advanced biomass cookstoves and biogas systems (Figure 8.10).16 Over 800 million of them would be living in rural areas. 14. In many countries, biomass is also used for space heating. The introduction of cleaner, more efficient devices for cooking does not necessarily reduce the need for traditional stoves or fires for heating. 15. For example, recent analysis by the Economic Commission for Latin America and the Caribbean (ECLAC) indicates that, while wood consumption for cooking and heating in Latin America and the Caribbean decreased steadily in the 1990s, it has risen this decade in many countries as a result of increasing poverty (ECLAC, et al., 2010). 16. For a discussion of advanced biomass stoves, see C. Venkataraman et al., 2010. For a discussion of biogas digesters, see www.unapcaem.org.

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Million

Figure 8.9 z Number and share of population relying on the traditional use of biomass as their primary cooking fuel by region, 2009 1 000

Figure 8.10 z Implication of reducing poverty for number of people relying on the traditional use of biomass for cooking by 2015 3 000 2 500

Population to be provided with clean cooking facilities

2 000 1 500 1 000 500 0

2009

2015 New Policies Scenario

2015 Universal Modern Energy Access Case

Looking further ahead to 2030 in the New Policies Scenario, the number of people relying on the traditional use of biomass remains at about 2.8 billion, one-third of whom live in sub-Saharan Africa (Table 8.5). The share of the population relying on biomass falls in all regions/countries, but the pace of decline is slowest in sub-Saharan Africa.17 Accordingly, building on the assumed improved results in 2015, the Universal Modern Energy Access Case means that an additional 1.7 billion people must achieve access to modern cooking facilities in the period 2016-2030. 17. The use of traditional biomass increases only in sub-Saharan Africa over the projection period (see Chapter 11).

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Table 8.5 z Number of people relying on the traditional use of biomass and share by region in the New Policies Scenario (million) 2015

Expanding household access to modern fuels would inevitably increase global demand for these fuels, notably oil, but only by a small amount. In the Universal Modern Energy Access Case, 445 million people switch to LPG stoves by 2015 and another 730 million by 2030. Assuming average LPG consumption of 22 kilogrammes (kg) per person per year,18 total world oil product demand by 2030 would be 0.9 million barrels per day (mb/d) higher than in the New Policies Scenario. This represents 0.9% of the projected 96 mb/d of global oil demand in 2030 (Figure 8.11). The additional oil demand associated with access to LPG in the Universal Modern Energy Access Case is roughly equivalent to 5% of oil demand in the United States today. In the 450 Scenario, where in 2030 global oil demand is 12.3 mb/d lower than in the New Policies Scenario, global oil demand still increases by only 1% in 2030.

The impact on greenhouse-gas emissions of switching to advanced biomass technologies or LPG is very difficult to quantify because of the diversity of factors involved, including the particular fuels, the types of stoves and whether the biomass used is replaced by new planting and that a sustainable forestry management programme is in place. But it is widely accepted that improved stoves and greater conversion efficiency would result in emissions reductions.

18. A weighted average based on WHO data for developing country households currently using LPG.

Investment needs in the Universal Modern Energy Access Case In the Universal Modern Energy Access Case cumulative investment of $756 billion, over and above investment in the New Policies Scenario, is needed. This comprises investment to achieve universal access to electricity and clean cooking facilities by 2030. Some 30% of the investment is needed in 2010-2015 to achieve the interim target. This will require additional annual investment of $41 billion in 2010-2015, or only 0.06% of average annual global GDP over the period. Investment needs for universal electricity access

Achievement of the targets associated with the MDG of eradicating extreme poverty and hunger by 2015 requires cumulative investment of some $223 billion in 2010-2015, and another $477 billion in 2016-2030 for access to electricity to be universal by 2030. Rural areas account for the bulk of additional household electrification in this period. The supply arrangements include grid and off-grid solutions (Figure 8.12). Consumer density is a key variable in providing electricity access: the cost per MWh delivered through an established grid is cheaper than that through mini-grids or off-grid systems, but the cost of extending the grid to sparsely populated areas can be very high and long distance transmission systems have high technical losses. Thus, decentralised solutions also have an important role to play and will, indeed, account for most of the investment over the projection period (Box 8.3). In our calculations, all urban and peri-urban households are assumed to be connected to the grid by 2015 in the Universal Modern Energy Access Case. About a third of rural areas are assumed to be similarly connected, while other households use off-grid and mini-grid options, including solar photovoltaics, mini-hydro, biomass, wind, diesel and geothermal. In the first year of obtaining access to electricity, the minimum annual consumption per household is assumed to be 250 kWh in rural areas and 500 kWh in 254

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urban areas. Household consumption rises every year over the Outlook period, until reaching the national average in 2030. Average household size is assumed to be five people. Box 8.3 z Renewable energy for rural applications Grid extension in rural areas is often not cost effective. Small, stand-alone renewable energy technologies can often meet the electricity needs of rural communities more cheaply and have the potential to displace costly diesel-based power generation options. Specific technologies have their advantages and limitations. Solar photovoltaics (PV) are attractive as a source of electric power to provide basic services, such as lighting and clean drinking water. For greater load demand, mini-hydro or biomass technologies may offer a better solution, though solar PV should not be ruled out of consideration as system prices are decreasing, a trend which can be expected to continue in the years to come. Moreover, solar PV can also be easily injected in variable quantity into existing power systems. Wind energy represents a good (and available) cost-competitive resource, with mini-wind prices below those of solar PV. Wind energy systems are capable of providing a significant amount of power, including motive power. One of the main advantages of renewable energy sources, particularly for household-scale applications, is their comparatively low running costs (fuel costs are zero), but their high upfront cost demands new and innovative financial tools to encourage uptake. To combine these different sources of energy in a power system supplying a mini-grid is probably the most promising approach to rural electrification. It is important that subsidised delivery mechanisms make provision for maintenance and repair. Improved irrigation is vital to reducing hunger and saving dwindling water resources in many developing countries. Drip irrigation is an extremely efficient mechanism for delivering water directly to the roots of plants. It increases yields and allows for introduction of new crops in regions and in seasons in which they could not be sustained by rainfall alone. Solar-powered pumps save hours of labour daily in rural off-grid areas, where water hauling is traditionally done by hand by women and children. These pumps are durable and immune to fuel shortages. In the medium term, they cost less than diesel-powered generators.19

The bulk of the investment for electrification by 2015 is incurred in developing Asian countries, primarily because economic growth is expected to be more rapid in these countries than in sub-Saharan Africa. The path to universal electricity access will require substantial financing in all developing regions, except Latin America, where access is already high. Cumulative investment of some $340 billion would be required to electrify all households in sub-Saharan Africa by 2030 (Table 8.6). 19. See, for example, www.self.org/benin.shtml.

*Compared with the New Policies Scenario. **Includes Middle East countries. ***Includes OECD and transition economies.

The additional power-sector investment, $33 billion per year on average in 2010-2030 in the Universal Modern Energy Access Case (Figure 8.13), is equivalent to just 5% of the average annual global investment in the power sector in the New Policies Scenario, or around one-fifth of the annual investment required in China’s power sector in 2010-2030. Adding $0.003 per kWh, some 1.8%, to current electricity tariffs in OECD countries could fully fund the additional investment. 256

*Compared with the New Policies Scenario. **Includes generation, transmission and distribution for both urban and rural grids.

8

Investment needs for universal access to clean cooking facilities We estimate that universal access to clean cooking facilities could be achieved through additional cumulative investment of $56 billion in 2010-2030, over and above that in the New Policies Scenario. Of this investment, 38% is required in the period to 2015 (Figure 8.14). Over the entire projection period, 51% of the cumulative investment goes to biogas systems in rural areas, 23% to advanced biomass cookstoves in rural areas and 26% to LPG stoves in both rural and urban areas. The average additional annual investment over the period to 2030 is $2.6 billion. Additional cumulative investment (2010-2030) of some $16 billion is required in China, $14 billion in India and $10 billion in other developing Asian countries (Table 8.7). The necessary cumulative investment to 2030 is $14 billion in sub-Saharan Africa.

These investment allocations are derived from assumptions regarding the most likely technology solution in each region, given resource availability and government policies and measures. Advanced biomass cookstoves, with emissions and efficiencies similar to those of LPG stoves, are assumed to cost $45. The cost of a biogas digester is assumed to be $400, the middle of the range of estimated costs for household biogas systems. An LPG stove and canister is assumed to cost $60. Infrastructure, distribution and fuel costs are not included in the investment costs. We assume one stove or biogas system per household in 2010-2030, thus replacement costs are not included. Developing Asia accounts for 80% of the total $28 billion investment needed for biogas systems, while China alone accounts for 50% of the total. In rural areas of subSaharan Africa, over 60% of the 645 million people that need to gain access to clean cooking facilities in 2010-2030 are provided with advanced biomass cookstoves and the remainder with LPG stoves and biogas systems. In rural areas of China, 55% of the target population are provided with biogas systems, 15% with advanced biomass cookstoves and the remainder with LPG stoves. Table 8.7 z Investment requirements for clean cooking facilities in the Universal Modern Energy Access Case* ($ billion) Africa Sub-Saharan Africa Developing Asia China India Other Asia Latin America Developing countries** World***

2010- 2015 4 4 16 7 5 3 1 21 21

2016-2030 9 9 24 9 8 6 1 35 35

2010-2030 14 14 40 16 14 10 2 56 56

*Compared with the New Policies Scenario. **Includes Middle East countries. ***Includes OECD and transition economies.

Financing the $756 billion, or $36 billion per year, needed to provide universal access to modern energy services in 2010-2030, compared with the New Policies Scenario, is a major challenge. So far, investments have been far below needs, especially in sub-Saharan Africa. Investments in electrification have been greater than in clean cooking facilities. All available sources of finance will need to be tapped: international funds, public/ private partnerships, bank finance at multilateral, bilateral and local levels, microfinance, loans and targeted subsidies. The financing mechanism adopted will need to be matched to the particular characteristics of the financing need: for example, the financial mechanisms appropriate to electrification differ according to the scale of the project and also differ from those required for expanding access to clean cooking facilities. 258

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The public sector can be expected to fund the costs of creating the necessary enabling environment, for example, establishing the appropriate policies, regulations and institutions, and will often need to finance the relatively large investments, such as additional generating capacity or transmission links. Indeed, in most developing countries, upfront public investment in developing national and local capacity is the most important ingredient in creating an environment which will encourage the private sector to assume at least part of the risk, essentially, where a commercial return can be reliably earned on the investment. Investment costs which fall to consumers are in a different category. Households will need loans (often on concessionary terms), leasing finance, grants and, even initial subsidies for both high initial investement costs as well as affordable operating costs. Local banks, as well as bilateral and multilateral agencies, will remain important sources of finance (World Bank Group, 2010). However, those institutions are unlikely to be in a position to provide the level of financing necessary to promote universal access to modern energy services. Existing energy programmes and funds (such as the Renewable Energy and Energy Efficiency Fund (REEF), the Climate Investment Funds administered by the World Bank and implemented jointly with other development banks,20 the Global Environment Facility and GTZ’s Energising Development) can be utilised to administer and distribute finance, but will need to be scaled-up significantly. Oil and gas-exporting countries have a source of financing that is not available to importing countries. WEO-2008 estimated that the cost of providing electricity and LPG stoves and canisters to those households without access in the ten largest oil and gasexporting countries in sub-Saharan Africa would be roughly equivalent to only 0.4% of the governments’ cumulative take from hydrocarbon exports through to 2030 (IEA, 2008). Such resource wealth offers a significant opportunity for economic development and poverty alleviation, if managed effectively. Greater efficiency of revenue allocation and greater accountability in the use of public funds are both important. Long-term financing for rural electrification is important. From the outset, financial provisions should extend long-term (five to ten years) support for the system, under contracts providing also for maintenance and upgrading. At least part of rural electrification should serve economic development activities as a means to generate revenue for maintenance and other operating costs with a view to the end of the support (Niez, 2010).

In contrast to investments for electrification, which are mainly funded by governments and institutional investors, cooking services involve products which are paid for by the consumer.21 The cost of an improved cookstove ranges from a few dollars to $45 (or in some cases considerably more). Where improved combustion leads to substantial, demonstrable reductions in global warming emissions, these costs may be offset by carbon finance through the Clean Development Mechanism or other mechanisms 20. For example, the World Bank’s Clean Technology Fund, Pilot Program for Climate Resilience and Scalingup Renewable Energy Program. 21. The provision of cookstoves by themselves is not enough for universal access. The supply chain, including distribution and production of stoves and fuels, including biomass, also needs to be considered.

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generating carbon credits.22 To support the uptake of clean cooking facilities, governments and donors need to invest in public awareness campaigns regarding the health and other benefits of clean cooking practices.

S P O T L I G H T

Are fossil-fuel subsidies in developing countries crowding out investments that would expand energy access? According to analysis for this Outlook, of the $312 billion of total fossilfuel subsidies in 2009, $252 billion were incurred in developing countries. Subsidies in countries with low access to modern energy at the household level (i.e. electrification rates less than 90% or access to modern cooking fuels of less than 75%) amounted to some $71 billion.23 Subsidies to kerosene, LPG and electricity in countries with low access to modern energy at the household level were less than $50 billion (see Table 19.3 in Chapter 19). Only a small share of oil-product subsidies are typically directed to cooking in the residential sector. Subsidies impose a significant burden on national budgets, discourage efficiency of fuel use, can create shortages and result in smuggling and illicit use of subsidised petroleum products. Pressure is building in international fora for governments to phase out blanket subsidies which are not well targeted to the poorest consumers. But phase-out policies must be carefully designed to avoid depriving the poor of basic needs. Direct financial assistance to poor families is probably more efficient than a subsidy to reduce the cost of a particular energy service. The annual average investment required to achieve universal access to modern energy services by 2030, $36 billion, is around 12% of spending in 2009 on fossilfuel subsidies in the 37 countries analysed (Figure 8.15).

Microfinance has proved particularly valuable to poor women. They tend to obtain better credit ratings than men and value highly the improvements that can be made to the quality of family life. In Bangladesh, for example, women have shown to default on loans far less often than men. In many cases, though, the scale of microfinance is insufficient to make large inroads into energy poverty.

22. The Gold Standard Foundation, an international non-profit organisation based in Switzerland, operates a certification scheme for Gold Standard carbon credits. 23. 37 countries are included in the IEA subsidy database. Those countries with low access to modern energy at the household level are: Angola, Nigeria, South Africa, China, Indonesia, Philippines, Thailand, Vietnam, Bangladesh, India, Pakistan and Sri Lanka.

Fossil-fuel subsidies in countries with low access to modern energy at the household level, 2009

Annual investment needs in the Universal Modern Energy Access Case

*Compared with the New Policies Scenario.

The poor often need to allocate a disproportionately high share of household budgets to energy services (Modi et al., 2005) and the poorest populations accordingly need distinct forms of help, even though their per-capita consumption is low. To address this, there is a long history of using subsidies to assist affordability. But ensuring that the benefits are provided only to the people most in need is difficult and consumers ideally should have a direct stake in the investment. A contribution by the consumer is critical to successful uptake. Households that pay for even a small fraction of the cost of modern energy services, whether it is an electricity connection, advanced biomass or LPG cookstove or biogas digester, are more likely to provide for maintenance and operating costs. Upfront costs for connections to the electricity grid or for fuel canisters and clean cooking stoves, can still remain too high for the poor and, in the most extreme cases, there may be no alternative to subsidising initially even a proportion of operating costs. One example, promoted by the EU-PV working group on developing countries is a Regulatory Purchase Tariff for off-grid electrification. Under this, the user pays only part of the tariff and the rest is covered by the government. This type of subsidy is focused on people with low consumption.

Monitoring progress and the Energy Development Index The IEA has devised an Energy Development Index (EDI) in order to better understand the role that energy plays in human development. It tracks progress in a country’s or region’s transition to the use of modern fuels. By publishing updates of the EDI on an annual basis the IEA hopes to raise the international community’s awareness of energy Chapter 8 - Energy poverty

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poverty issues and to assist countries to monitor their progress towards modern energy access (Box 8.4). The EDI is calculated in such a way as to mirror the UNDP’s Human Development Index and is composed of four indicators, each of which captures a specific aspect of potential energy poverty.24  Per-capita commercial energy consumption: which serves as an indicator of the

overall economic development of a country.  Per-capita electricity consumption in the residential sector: which serves as

an indicator of the reliability of, and consumer’s ability to pay for, electricity services.  Share of modern fuels in total residential sector energy use: which serves as an

indicator of the level of access to clean cooking facilities.  Share of population with access to electricity.

A separate index is created for each indicator, using the actual maximum and minimum values for the developing countries covered (Table 8.8). Performance in each indicator is expressed as a value between 0 and 1, calculated using the formula below, and the EDI is then calculated as the arithmetic mean of the four values for each country. Indicator = Indicator =

actual value — minimum value maximum value — minimum value

Table 8.8 z The minimum and maximum values used in the calculation of the 2010 Energy Development Index Indicator

toe = tonne of oil equivalent. 24. The choice of indicators is constrained by the type of data related to energy poverty that is currently available. For example, the per-capita commercial energy consumption figure is one indicator of overall economic development of a country, but for reasons of data deficiency it fails to take account of biomass resources, including wood, charcoal and biofuels, which are used for productive activities in developing countries. Biomass data is seldom disaggregated in a sufficient manner to capture this reality. With the introduction of low-emission, high-efficiency stoves, biomass consumption will decline in many countries. Yet the EDI cannot adequately compensate for the fact that this decline will be slower than in those countries where households switch to liquid fuels for cooking, even though the impact on energy poverty could be similar. The countries included in the EDI are those for which IEA collects energy data.

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Box 8.4 z Measuring progress with energy poverty indicators A robust set of indicators for measuring energy poverty is needed to provide a rigorous analytical basis for policy-making. Indicators: z Improve the availability of information about the range and impacts of

options for action and the actions that countries are taking to increase access to energy. z Help countries monitor actions they take to meet their agreed target. z Enhance the effectiveness of implementation of such policies at national and

local levels. There are numerous examples of single indictors and composite indices to measure concepts related to development and energy (Bazilian et al.,2010). The prime weakness of the various measures is related to data paucity and quality. In theory, energy development indicators should quantify not only the availability of energy — essentially a supply-side approach — but also measure to what extent the available supply is used and how much this contributes to the fulfilment of basic needs. The Earth Institute of Columbia University has pointed out that quantifying the value of some energy services, such as mechanical power or lighting, might benefit from the use of proxy indicators. Mechanical power is one of the largest energy services in terms of volume. It tends to generate a large return on investment and provides significant development leverage. Statistics on energy consumption for mechanical power, however, are not collected. An “ideal” energy development index could be based largely on the energy access recommendations set out by the UN Millennium Project.25

Computing a comprehensive energy development index will require the creation of new or augmented data-gathering systems and activities. A robust set of measurement indicators is crucial for informing and ensuring appropriate national policy-making, as well as effective international co-operation. Designing the right indicators and implementing a reporting system can help move energy access to the heart of a development plan. The World Energy Outlook has maintained databases on electricity access and reliance on traditional biomass in rural and urban areas since 2002 (IEA, 2002). These databases are updated annually and will be expanded with the emergence of more comprehensive data-gathering systems.

25. The Millennium Project was commissioned by the UN Secretary-General in 2002 to develop a concrete action plan for the world to achieve the Millennium Development Goals (see footnote 2). A common finding of the Millennium Project was the urgent need to improve access to energy services as essential inputs for meeting each MDG. The Millennium Project set out ten recommendations for priority energy interventions which national governments should take to support achieving the MDGs at the national level (Modi et al., 2005).

Figure 8.16 ranks countries using the four energy development indicators discussed above. Except for South Africa, all sub-Saharan African countries appear in the bottom half of the EDI. Gabon ranks second in sub-Saharan Africa, behind South Africa but 23 places lower. The ranking of countries in Asia varies greatly; Myanmar and Cambodia are in the bottom ten countries, while Malaysia is in the top ten. Pakistan has the highest EDI ranking of countries in South Asia, while Venezuela has the highest ranking of Latin American countries. Oil net exporting countries, except for those in subSaharan Africa, are all in the top third of the EDI ranking. Given the substantial contribution of energy services to advancing human development, it is not surprising that the EDI results are strongly correlated with those of the Human Development Index (HDI) (Figure 8.17).26 The HDI is composed of data on life expectancy, education, per-capita GDP and other standard-of-living indicators at the national level.

Human Development Index

Figure 8.17 z Comparison of the Human Development Index to the Energy Development Index 1.0 0.8 0.6 0.4 0.2 0

Many countries have made notable progress in improving access to electricity and clean cooking facilities since 2004, when the Energy Development Index was first created (IEA, 2004). In all countries both the absolute number with access and the share of the population with access have increased (Figure 8.18). In China, substantial progress has been made in access to modern cooking fuels. In Angola and Congo, where the share of the population with electricity and access to modern cooking fuels has expanded, most of the achievement has come from urban areas. While there has been progress on both fronts in Bangladesh, Sri Lanka and Vietnam, more progress has been made in household electrification than in the provision of access to modern cooking fuels.

Other potential indicators The World Energy Outlook will update the Energy Development Index on an annual basis. As more and better data become available, the EDI will also be augmented in order to enhance the monitoring of progress towards universal modern energy access. This section explores other possible indicators. Figure 8.19 shows the relationship between fuel use and income across a range of developing countries. In low-income countries, final consumption of energy in the residential, service, industry and transport sectors is low and is comprised mainly of biomass. In high-income developing countries, the fuel mix is much more diverse and the overall amount of energy consumed is much higher.

toe

Figure 8.19 z The relationship between per-capita final energy consumption and income in developing countries 1.2

40% - 75% 5% - 40% <5% Share of population with an income of less than $2 per day

Note: Average per-capita final energy consumption is 3.1 toe in OECD countries. Other petroleum products are mostly consumed in the transport sector.

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Demand for mobility, which is indicated where the share of other petroleum products in final energy consumption is high, is much greater in countries with a very low percentage of the population living on less than $2 a day. The indicators used in the EDI capture the quantity of energy consumed as well as rates of access. Other useful indicators would capture the quality of energy consumed. Figure 8.20 provides an illustration of the quality of energy services for cooking and lighting as income rises at the household level. The figure is reflective of energy consumption in rural households, but some of the principles also apply to peri-urban and urban households. The concept of a simple “energy ladder”, with households moving up from one fuel to another, does not adequately portray the transition to modern energy access, because households use a combination of fuels and technologies at all income levels. This use of multiple fuels is a result of their differing end-use efficiency, of affordability and of social preferences, such as a particular fuel for cooking. Moreover, use of multiple fuels improves energy security, since complete dependence on a single fuel or technology leaves households vulnerable to price variations and unreliable service.

Quality of delivered energy services

Figure 8.20 z The quality of energy services and household income Cooking

The indicator of the quality of delivered energy services on the vertical axis in Figure 8.20 is designed to capture a variety of dimensions, including cleanliness, efficiency and affordability. Because the amount of energy delivered from traditional technologies, such as a three-stone fire or kerosene/diesel lanterns, is much lower than that from modern services, such as electricity, poorer households pay a much higher share of their Chapter 8 - Energy poverty

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income on energy services. A study of rural energy use in Bangladesh found that, for example, the cost of each kilolumen-hour from incandescent light bulbs or fluorescent tubes is less than 2% of the cost of comparable lighting services from kerosene lamps (Asaduzzaman, Barnes and Khandker, 2009). Access to electricity accordingly can reduce total household energy costs dramatically, if upfront costs related to the connection are made affordable. In addition, successful energy efficiency initiatives reduce electricity demand, which has the secondary benefit that existing generation plants can be used to supply new households, thereby reducing the need for capacity additions. Box 8.5 z Going beyond household access: indicators at the village and national level Village level energy services, both for electricity and mechanical power, are extremely important. In poor rural areas, providing household level electricity service is often not economically feasible. The cost of service provision is higher than in urban areas, because support infrastructures for maintenance is lacking and because low population density increases the cost per household. Where household level electrification is not feasible, providing electricity at the village level for productive activities and basic social services can be a useful stepping stone. Moreover, village level energy installations, e.g. mechanical power for food processing and other productive activities, irrigation, and clean water and sanitation, have a significant impact on poverty, health, education and gender equality. While mechanical power is critical to develop industrial and productive activities necessary to local development, quantified objectives defining rates of access to mechanical power are rarely integrated into national strategies. By the end of 2009, less than 5% of developing countries had defined such targets. Those few countries that had established targets on access to mechanical power—Benin, Cameroon, Central African Republic, Mali, and Togo—are all in sub-Saharan Africa (see Table 8.10). In addition to the impact at the household level, unreliable electricity service constrains economic activity and constitutes a severe obstacle to business operation and growth (Table 8.9). According to the World Bank, countries with underperforming energy systems may lose 1 to 2% of economic growth potential annually as a result of electric power outages, over-investment in backup electricity generators, energy subsidies and inefficient use of energy resources (World Bank, 2009).

Table 8.9 z Indicators of the reliability of infrastructure services Delay in obtaining electricity connection (number of days) Electrical outages (days per year) Value of lost output due to electrical outages (% of turnover) Firms maintaining own generation equipment (% of total)

Sub-Saharan Africa 79.9 90.9 6.1 47.5

Developing countries 27.5 28.7 4.4 31.8

Source: World Bank (2007).

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Policy implications How can countries embark on a dynamic path that will eventually lead to universal access to modern energy services? Experience shows that success can be achieved in a variety of ways. Cambodia, Mali and Madagascar have given support to private developers through rural electrification funds. Bangladesh and Nepal have developed local co-operatives, owned by consumers. Smart subsidy schemes to provide electricity to rural households, such as ‘output based aid’ subsidies, have been developed in some countries, e.g. Senegal and Mozambique, and a similar approach has been used in Colombia to connect poor households to natural gas services. In Mali, multifunctional platform27 projects have been developed to provide mechanical power and their success has led to similar programmes being adopted in other African countries, such as Burkina Faso, Ghana, Guinea and Senegal. To meet overall universal modern energy access objectives, however, these approaches need to be scaled-up significantly and applied more widely.28 Increasing access to modern energy services requires, first, the integration of energy access into national development strategies, preferably with support from the UN system. Strong and sustainable financial, institutional and technology frameworks must be set up and capacity building undertaken at the local and regional levels: developing the capacity of national and local organisations, the private sector and communities themselves to provide appropriate energy technologies and services. In Nepal, for example, well over half of the total programme cost for the implementation of a programme to provide micro-hydropower and improved cooking stoves was dedicated to capacity development (UNDP and AEPC, 2010). Setting national goals and targets is important, but it is not enough, without careful monitoring of progress. Greater regional co-operation can avoid unnecessary expansion of electricity generation capacity in the future. Coordination within a country and between regional governments can greatly enhance the efficacy of electricity projects and contribute to wider benefits: in Africa, in particular, regional power pools appear to make a valuable contribution to regional integration, which is widely perceived as one of the best engines of Africa’s development.

About half of developing countries have set up electricity access targets at the national, rural and/or urban level. Objectives vary among countries. While some countries, such as Bangladesh, Bhutan, Botswana, Ghana, India, Nepal, South Africa or Swaziland aim to reach universal access within the next 5 to 17 years, others have defined intermediate goals, such as Malawi or Rwanda, that aim to achieve 30% and 35% electrification rates respectively by 2020. Both Laos and Indonesia have a target to electrify 90% of the population by 2020, in the latter case involving expanding access to some two million new subscribers each year. Cambodia has a target to increase its rural electrification rate from 12% today to 70% by 2030. 27. The multifunctional platform is built around a diesel engine, which can also run off jatropha oil. It can power various tools, such as a cereal mill, husker, alternator, battery charger, pump, welding and carpentry equipment. It can also generate electricity and be used to distribute water. 28. See UNDP and AEPC, 2010 and UNDP, 2006.

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Worryingly, very few developing countries have set targets for access to modern cooking fuels or improved cookstoves or for reducing the share of the population relying on traditional biomass (Table 8.10). Table 8.10 z Number of developing countries with energy access targets Developing countries (total)

of which: sub-Saharan Africa

Electricity

68

35

Modern fuels

17

13

Improved cookstoves

11

7

5

5

Mechanical power

Note: Based on UNDP’s classification of developing countries. Source: UNDP and WHO (2009).

Despite the demonstrable health consequences associated with current cooking practices in many developing countries, access to clean cooking facilities has received very little high-level attention, and, not surprisingly, very little progress has been made. Adequate training and support services have been lacking, together with the market research necessary to determine the concerns of the women who would be using the stoves and their different cooking habits. Where initiatives have been taken, governments are becoming aware of the limitations of policies to encourage switching to liquid cooking fuels, such as LPG, and are putting in place strategies to increase the use of advanced biomass cookstoves and biogas systems (Box 8.6).29 Box 8.6 z Initiatives to improve the efficiency of biomass for cooking The Indian Ministry of New and Renewable Energy (MNRE) launched a “National Biomass Cookstove Initiative” in December 2009. The initiative aims to achieve for all households a quality of energy services from cookstoves comparable to that from clean energy sources, such as LPG. A large proportion of India’s population, some 72% of the total population and 90% in rural areas, uses biomass for cooking. Providing a clean cooking energy option would yield enormous gains in terms of health and socio-economic welfare. Advanced biomass cookstoves also greatly reduce the products of incomplete combustion, which are greenhouse-gas pollutants, thus helping combat climate change.

The Rwandan government estimates that the value of firewood and charcoal consumed for cooking in 2007 was on the order of $122 million, or 5% of GDP (Ministry of Infrastructure, Republic of Rwanda, 2010). About 50% of this was used in rural areas. The government has devised a strategy to increase the efficiency and reduce the environmental impact of using biomass for cooking.

29. The heightened awareness of the need to improve the use of biomass for cooking is driven by different factors among countries. The most important include high oil prices, global recession, unreliable supplies of liquid fuels, and the illegal diversion of LPG and kerosene to the industry and transport sectors.

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Key components are: building capacity among equipment manufacturers and importers, in order to make available modern appliances for the use of biomass; developing a quality label, promoting the use of these modern appliances; and launching a long-term publicity and awareness campaign to encourage households, institutions and businesses to adopt the new equipment. From 2001 to mid-2010, the programme for the Development and Promotion of Biogas Utilization in Rural China (DPBURC) built some 30 million biogas systems, benefitting around 105 million people in rural areas. Measures that contributed to this achievement included: setting minimum technical and quality control standards; adapting technology to match local resources; focusing government financial support on the poorest; and providing technical support to manufacturers of biogas appliances and owners. The biogas systems are used for cooking, electricity, sanitation and the manufacture of fertiliser. On average, each household using a biogas digester saves 500 yuan ($74) every year from reduced use of fuelwood, electricity, chemical fertiliser and pesticides (Tian and Song, forthcoming). By the end of 2010, the total number of biogas systems is likely to reach 40 million, 30% of the estimated potential in China. To summarise, providing universal access to modern energy services at the household level depends upon recognition by the international community and national governments of the urgency of the need, and long-term policy commitment as part of strategic development plans. These need to make provision for the creation of strong institutional, regulatory and legal frameworks and financing from all available sources, including the private sector. Appropriate technological choices need to be factored in. International aid will be needed to subsidise investments in the production and distribution of both electricity and clean cooking fuels, in capacity building and in creating an institutional system that integrates these different areas over the long term and addresses climate change simultaneously.30 International development organisations can support research, design and development of appropriate technologies. Promising approaches include reliance on renewable energy in rural applications and the use of locally-produced bioenergy to generate electricity. International development organisations should take the lead in collecting, compiling and sharing knowledge and in developing tools and indicators to measure progress. Prioritising energy access as a key driver of social and economic development is a first step towards universal modern energy access. The way forward will require:  Commitment from the international community to the objective of achieving

universal access to electricity and to clean cooking facilities by 2030.  Establishment of national goals for access to modern energy services, supported by

Renewable energy has been growing rapidly in the last decade, becoming an important component of energy supply. Government intervention in support of renewables has grown, reflecting efforts to reduce carbon-dioxide emissions and to diversify energy supplies. The incentives offered, alongside rising fossil-fuel prices and the expectation that these will stay high in the future, have made renewables attractive to many investors. This part of the report provides insights into recent and future trends in renewable energy. Chapters 10, 11 and 12 focus on their application in the electricity, heat and transport sectors respectively. Chapter 9 brings together trends across all sectors and discusses issues common to all renewables, including their costs and benefits. Each chapter presents a brief overview of the results across the three scenarios, but with the main focus on the New Policies Scenario, which illustrates where currently planned policies, if implemented in a relatively cautious way, will take us. For ease of comparison, the main findings of the 450 Scenario are presented briefly in a box in each chapter.

The analysis of renewables for electricity in Chapter 10 includes the quantification of incentives in place to support renewables, the support needed up to 2035, and the impact on electricity prices of greater use of renewables. It also discusses how different renewables can be integrated into the network, with an estimate of the associated costs. This chapter takes a close look at two specialised topics: first, offshore wind power, with a focus on northern Europe, and second, renewables in Middle East and North Africa, a region that has some of the best solar resources in the world and could become an exporter of solar power to Europe. Though heating is the principal energy service, as a sector it has received relatively little attention. Despite problems with data availability, we have provided an overview of the main trends in renewables for heat in Chapter 11. The chapter opens with a discussion of total demand for heat, and elaborates the large potential for renewables, including biomass, solar and geothermal heat. Chapter 12 on renewables for transport focuses on biofuels, but covers briefly renewables-based electricity and hydrogen used in transport. It also discusses biofuels-related greenhouse-gas emissions, a controversial subject in recent years. Similar to Chapter 10, it quantifies government support and looks into the costs of biofuels.

HOW RENEWABLE ENERGY MARKETS ARE EVOLVING How green will the future be? H

I

G

H

L

I

G

H

T

S

z The use of modern renewable energy is projected to expand rapidly to

2035 in all three scenarios presented in this Outlook. The rates of growth in each scenario reflect assumptions about different levels of intensity of government policies aimed at reducing greenhouse-gas emissions and diversifying the energy supply mix. The supply of modern renewable energy — including hydro, wind, solar, geothermal, modern biomass and marine energy — increases from 840 Mtoe in 2008 to between 1 900 Mtoe and nearly 3 250 Mtoe in 2035, depending on the scenario. z In the New Policies Scenario, the share of renewables in global electricity

generation increases from 19% in 2008 to almost a third in 2035. The share of modern renewables in heat production in industry and buildings increases from 10% to 16%. Demand for biofuels grows four-fold between 2008 and 2035, meeting 8% of road transport fuel demand by the end of the Outlook period. z Investment needs in renewable energy to produce electricity are estimated at

$5.7 trillion (in year-2009 dollars) over the period 2010-2035 in the New Policies Scenario. Biofuels need another $335 billion. Overall, renewables investment needs are greatest in China, which has now emerged as a leader in installing wind turbines and photovoltaics, as well as a major supplier of these technologies. z We estimate that government support for electricity from renewables and for

biofuels cost $57 billion in 2009, up from $44 billion in 2008 and $41 billion in 2007. This support grows to $205 billion by 2035 in the New Policies Scenario, or 0.17% of global GDP. Between 2010 and 2035, 63% of the support goes to renewable electricity and 37% to biofuels. Large-scale government support is needed to make renewables cost competitive with other energy sources and technologies and to stimulate the required technological advances. z Several benefits may be adduced to justify government support for renewables.

Recent trends Policy support for renewable energy has increased considerably over the past decade. Two drivers underpin this trend: first, the effort to constrain growth in greenhousegas emissions and, second, concerns to diversify the supply mix (promoted particularly by high oil prices, especially in 2005-2008). To address these concerns, more and more governments are adopting targets and taking measures to increase the share of renewables in the energy mix. Job creation through renewables has been another factor in government support, especially as a contribution to reducing unemployment following the economic and financial crisis. Total primary renewable energy supply, including traditional biomass, grew from 1 319 million tonnes of oil equivalent (Mtoe) in 2000 to 1 590 Mtoe in 2008. Its share in total energy supply remained roughly stable during that period, at around 13%. Biomass is by far the most important source of renewable energy in this wider definition (the term “modern renewables” excludes the traditional use of biomass).1 Biomass use amounted to 1 225 Mtoe in 2008, most of which was used in traditional ways by some 2.7 billion people in developing countries (see Table 8.1 in Chapter 8). The use of modern biomass is smaller (478 Mtoe in 2008) but is rapidly growing, particularly as it is being used more intensively to produce electricity and as feedstock for making transport fuels. Hydropower is the second-largest renewable energy source in primary energy demand (276 Mtoe) and the largest source of renewables-based electricity. Wind, solar, geothermal and marine power have been growing very quickly in recent years, but their overall contribution to primary energy supplies remains modest. The characteristics of the main forms of energy are summarised at the end of the chapter. Renewables-based electricity output increased by nearly a third from 2000 to 2008. While most of the 900 TWh increase came from hydropower, new forms of renewables grew very rapidly, notably wind power, which expanded seven-fold. Solar photovoltaic (PV) electricity production grew 16-fold during the same period. Biomass use and geothermal power both increased too, although at a moderate pace, while marine power and concentrating solar power are just now beginning to take-off. Growth in the use of renewables for producing heat at the point of use (and in heat from district heating systems) was much more modest, as government policies to support renewables tend to focus more on electricity and transport. The use of traditional biomass has increased since 2000, despite efforts to provide the poor with access to modern fuels.

Biofuels are supplying a growing share of transport fuels. Global consumption of biofuels, used almost exclusively in road transport, increased five-fold over the period 2000-2008, reaching 1 million barrels per day (mb/d) and meeting almost 3% of total fuel demand in road transport. While oil demand for road transport fell in 2009 1. Modern renewables encompass all renewable energy sources other than traditional biomass, which is in turn defined as biomass consumption in the residential sector in developing countries and refers to the use of wood, charcoal, agricultural residues and animal dung for cooking and heating. All other biomass use is defined as modern.

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(for the first time since 1980), in response to higher prices and shrinking economic activity, biofuels use continued to grow, as production capacity — spurred in most countries by government support — expanded.

Outlook for renewable energy Key parameters affecting the outlook Despite the impressive growth in renewable energy in recent years, most of the world’s energy needs are still met by fossil fuels and most of the increase in energy demand since 2000 has also been met by fossil fuels. On a global scale, 19% of electricity came from renewables in 2008, a share that has changed very little since 2000, while the shares of coal and gas have increased by 2 and 3.6 percentage points, respectively. In transportation, oil use is about fifty times greater than that of biofuels. The use of fossil fuels for heat is ten times higher than the use of modern renewables. The renewables resource base is very large and can amply meet a large proportion of energy demand. However, most renewables are not cost competitive under present market conditions and rely on various forms of incentives. Consequently, the existence of government programmes to make renewables attractive to investors and create markets for them is the most important factor affecting the expansion of renewable energy. Such incentives already exist in many countries and are reflected in the significant rate of increase in the use of renewable energy. Often in combination with financial incentives, a number of countries have imposed a requirement on suppliers to raise the share of renewables in electricity production or in transport fuels. The use of carbon markets as a means to promote renewables is limited at present, applying, on a large-scale, only in the European Union (EU). The Clean Development Mechanism (CDM) has contributed to the expansion of renewables in developing countries. Overall, however, it is direct government support, rather than pricing of CO2, that drives the growth in renewables at present. Policies to facilitate the integration of variable renewables (such as wind power) into networks are important. Such policies can range from better planning for transmission projects to the development of smart grids, the creation of demand response mechanisms and the promotion of storage technologies.

Policies and strategies to support the development of large hydropower differ, but are no less important. While large hydropower is cost competitive almost everywhere in the world and does not require financial incentives, new applications demand a sensitive approach to the adverse environmental impacts, including rehabilitating populations that are displaced as a result of the construction of dams and adopting integrated water management practices. Cost reductions are essential to large-scale development of renewable energy. Renewable energy technologies are capital-intensive, requiring significant upfront investments, and most cannot currently compete on price with conventional technologies. For many renewable energy technologies, however, costs have already Chapter 9 - How renewable energy markets are evolving

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9

come down significantly. The scope for further cost reductions for these emerging technologies is generally greater than for the more mature fossil-fuel technologies, as fossil-fuel prices are expected to increase in the future. Government support for renewables can lead to technology improvements and the widespread deployment that is necessary to make renewables cost competitive. Large-scale development of renewable energy depends on access to finance. Because of their capital-intensive nature, these renewables projects are largely dependent on lending. Attracting finance is likely to be particularly difficult in poorer countries.

Projections by scenario A substantial increase in modern renewable energy to 2035 is projected in all three scenarios (Figure 9.1), with government policies driving most of the growth. The largest increase in renewables occurs in the 450 Scenario, driven by policies to achieve deep cuts in CO2 emissions (see Chapter 1 for the definitions of the scenarios). The renewable energy policies underlying the scenarios are discussed in Chapters 10 to 12. Despite the data limitations, we provide projections for heat. Box 9.1 z IEA statistical conventions and renewable energy measured at primary energy level

The choice of methodology to calculate the total primary energy demand (TPED) that corresponds to a given amount of final energy (such as electricity and heat) is important in the determination of the respective shares of each contributing energy source, but not straightforward. This is particularly true for the calculation of the shares of renewable energy sources. The IEA uses the physical energy content methodology to calculate TPED. For coal, oil, gas, biomass and waste, TPED is based on the calorific value of the fuels. For other sources, the IEA assumes an efficiency of 33% for nuclear and 100% for hydro, wind and solar photovoltaics (PV). For geothermal, if no country specific information is available, the primary energy equivalent is calculated using 10% for geothermal electricity and 50% for geothermal heat. As a result, for the same amount of electricity produced, the TPED calculated for biomass will be several times higher than the TPED for hydro, wind or solar PV. The IEA is in the process of determining the appropriate level of efficiency for concentrating solar power. For the purposes of this report, an average efficiency of 40% has been used.

Modern renewables grow rapidly in all scenarios, from 843 Mtoe in 2008 to between 1 900 Mtoe (in the Current Policies Scenario) and 3 250 Mtoe (in the 450 Scenario) by 2035, or up to almost four times the current level. The use of traditional biomass rises slightly to 2020 and then declines by 2035 in all three scenarios, although at different rates by region (see Chapter 8). Consequently, the share of traditional biomass in all renewables diminishes over time. 278

Across all scenarios, biofuels for transport grow more rapidly than renewables for heat and electricity, but from a relatively low base. They increase between three to eight times above 2008 levels by 2035 (Figure 9.2). The very large increase in the 450 Scenario is driven by higher penetration of advanced biofuels, which achieve lower overall unit costs and have lower land requirements. The biofuels share in total transport reaches between 5% and 14% in 2035, up from 2% in 2008 (Table 9.1). Most of the additional demand for biofuels comes from road transport. Renewables for heat2 increase in absolute terms between 73% and 153%, meeting up to 21% of total heat demand. In the electricity sector, renewables output increases from about 3 800 terawatt-hours (TWh) to between 8 900 TWh and 14 500 TWh (+135% to +284%). The share of renewables in total electricity generation rises from 19% in 2008 to 23% in 2035 in the Current Policies Scenario, 32% in the New Policies Scenario and 45% in the 450 Scenario. Table 9.1 z Global modern renewable energy supply and shares in total by scenario 2035

In the New Policies Scenario, the use of modern renewable energy triples over the course of the next twenty-five years, growing from 843 Mtoe in 2008 to 1 376 Mtoe in 2020 to 2 409 Mtoe in 2035. Its share in total primary energy demand increases from 7% to 9% and then 14%. Consumption of traditional biomass drops from 746 Mtoe in 2008 to 722 Mtoe in 2035, after a period of modest increase from now to 2020.

Figure 9.3 z Modern renewables primary energy demand by region in the New Policies Scenario Other non-OECD

Demand for renewable energy increases substantially in all regions, with dramatic growth in some areas. Demand for renewables increases six-fold between 2008 and 2035 in China and four-fold in India (Figure 9.3). Demand remains highest in the European Union, where the increase is driven by policies to raise the share of 280

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renewables to 20% in gross final consumption in 2020, related to the commitment to cut greenhouse-gas emissions by 20% relative to 1990. The United States follows closely, as a result of large increases in renewables-based electricity generation and in biofuels use. Global electricity generation from renewables increases from 3 800 TWh to 11 200 TWh and its share in total electricity generation grows from 19% to almost a third. The use of modern renewables for heat production in the industry and buildings sectors increases from 312 Mtoe to 660 Mtoe, with their share in total heat supply rising from 10% to 16%. Demand for biofuels grows four-fold between 2008 and 2035. Biofuels meet 8% of road transport demand in 2035, but just 1% of aviation fuel demand. Key results of the New Policies Scenario are summarised in Table 9.2.

Table 9.2 z Shares of renewable energy by sector and region in the New Policies Scenario Electricity

Note: Electricity = share of renewables in total electricity generation; heat = share of renewables for heat in total demand for heat; biofuels = share of biofuels used in road transport in total road transport and share of biofuels used in aviation in total aviation fuel.

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Box 9.2 z Renewables in the 450 Scenario In the 450 Scenario, total primary energy demand of modern renewables grows four-fold between 2008 and 2035, from 843 Mtoe to nearly 3 250 Mtoe. Renewables supply 45% of total electricity output by 2035 and 21% of total heat. In the transport sector, 14% of transport fuel comes from biofuels in that year. Changes of this magnitude reflect the extent of government intervention assumed in this scenario, in order to limit the global temperature increase to 2°Celsius, and its dramatic implications for the renewable industry. This scenario is also accompanied by almost universal removal of fossil-fuel consumption subsidies. The main policy drivers in the electricity sector are emission trading schemes in OECD and major non-OECD economies, complemented by incentives to support those technologies that are not competitive. Growth in biofuels is underpinned by agreements to limit CO2 emissions per car kilometre driven and in the aviation sector. The use of renewables for heat in industry increases both as a result of the emissions trading schemes that cap emissions in this sector and policies supporting renewables specifically. In buildings, renewables supply a much greater share of heat, owing to national policy plans that promote renewables alongside energy efficiency.

Total primary biomass use — both traditional and modern — in the New Policies Scenario increases from 1 225 Mtoe in 2008 to nearly 2 000 Mtoe in 2035.3 Over 60% of total biomass used in 2008 was traditional biomass, which was consumed in developing countries (essentially in India and sub-Saharan Africa), mainly for cooking and space heating. This share drops to 37% by 2035, both because people who rely on it switch to modern fuels and technologies), and because demand for modern biomass increases substantially as a result of government policies.

Global modern primary biomass consumption nearly triples between 2008 and 2035. The pattern of use changes over time (Figure 9.4). The main application of modern biomass today is in industry, where it is mainly used in the production of process steam, while the power sector is the second-largest user. Over the period 2008-2035, most of the increase in biomass comes from the electricity sector and transportation. By 2035, power generation becomes the largest biomass-consuming sector, ahead of industry. The share of biofuels in modern biomass use grows from 10% in 2008 to 16% in 2035. Although biofuels are expected to become increasingly cost competitive with gasoline and diesel over the Outlook period, the allocation of biomass to the various consuming sectors is driven more by government incentives and priorities than by market economics (see Chapter 12).

3. Total biomass use is discussed in this section because it comprises several different uses, which may be competing for the same resource. This is not generally the case for other forms of renewable energy, so these are discussed in the subsequent chapters, which detail renewables use in particular applications.

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Figure 9.4 z World modern biomass primary demand by sector in the New Policies Scenario 100%

Other sectors Buildings

80%

Transport Industry

60%

Power generation

40% 20% 0%

2000

2008

2020

2035

Note: Power generation includes biomass used in combined heat and power plants to produce electricity and heat, and in heat only plants.

Global investment in renewable energy assets, as specifically defined in this section (Box 9.3), grew seven-fold over the period 2004-2008, from $17 billion to $126 billion. As the global financial crisis broke, credit dried up and companies postponed projects as a result of reduced liquidity and uncertainty over demand. Consequently, investment in renewables fell to $115 billion in 2009, a 9% drop from 2008. Investment in biofuels fell sharply, from $18 billion to $7 billion, a drop of over 60%. The biofuels industry was directly affected by the fall in oil prices and the lower overall demand for oil, which limited the amount of biofuels that could be absorbed by gasoline and diesel blending pools (IEA, 2009a). Regulatory changes related to the environmental benefits of conventional biofuels technology, for example, in Germany and the United States, also deterred investment. The renewables electricity sector was much less affected, mainly because of large and continued expansion in wind power projects in China. Global investment in electricity projects remained stable between 2008 and 2009, at around $108 billion.

4. The discussion in this section draws largely on investment data from Bloomberg New Energy Finance, which are different from the investment data used elsewhere in WEO-2010. The differences are outlined in Box 9.3.

When is biomass production sustainable? Biomass is a renewable energy source so long as the growth of new crops and trees replenishes the supply. It is a carbon neutral energy source on that basis, as it releases only the CO2 that was captured during its growth and an equivalent amount of CO2 is recaptured in the regrowth. In that sense, biomass can greatly contribute to CO2 emissions reductions, relative to fossil-fuel use. However, its production does give rise to several concerns. Deforestation is a major problem in the developing world and, although it has decreased over the past decade, it continues at an alarmingly high rate in many countries (FAO, 2010). Planting crops for biofuels production — for instance, palm oil — has led to the clearance of forested land in some developing countries. Such deforestation has adverse social impacts on the local population and may lead to soil erosion and loss of biodiversity. Growing biomass crops, besides increasing water consumption, may also require intensive use of fertiliser to increase productivity, potentially resulting in water pollution. The life-cycle greenhouse-gas emissions of biomass have also come under scrutiny. Concern has been directed particularly at biofuels, as some (e.g. corn ethanol) may provide only marginal emission savings on a life-cycle basis, or even result in an increase in emissions. The calculation of life-cycle emissions from biofuels takes into account emissions from the energy used in conversion and from land use changes (Chapter 12). The production process of the fuels gives rise, on average, to a lower level of greenhouse-gas emissions than the cultivation of the feedstock (UNEP, 2009). This is particularly true when the feedstock comes from sugar cane or ligno-cellulosic feedstocks (IEA, 2009b). The emissions attributable to feedstock cultivation are lower when no land use change is involved. There is also some concern that diverting food crops to biofuels could increase prices and exacerbate hunger in poor countries, though some studies have indicated that there should be enough land available globally to feed the increasing world population and at the same time produce sufficient amounts of biomass feedstocks (e.g. Fischer et al., 2001; Smeets et al., 2007). However, environmental constraints relating to water and fertiliser use could reduce the amount of land that could realistically be available for biomass cultivation in the future, leading to a need to resolve the food-versus-fuel debate (Doornbosch and Steenblik, 2007). The adverse environmental and social impacts can be minimised. Positive steps include: using marginal or under-utilised lands to avoid deforestation and competition with food production; focusing on advanced biofuels technologies that rely on ligno-cellulosic feedstocks; achieving greater productivity in growing biomass crops; making greater use of wastes, residues and surplus forestry; using high-efficiency biomass technologies for heat and power; and achieving higher standards of sustainable land use in the developing world.

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Several government initiatives already address these concerns, including: the European Commission’s Renewable Energy Directive; Germany’s biofuels sustainability decree; the US Renewable Fuels Standard and Brazil’s AgroEcological Zoning for Sugar Cane (IEA, 2010a). Several non-governmental initiatives promote the debate (for example, the Roundtable on Sustainable Biofuels, the mission of which is to develop standards for sustainable biofuels production). Box 9.3 z Definitions of investment data The Bloomberg New Energy Finance (BNEF) data used throughout this section cover investment in new electricity assets (excluding hydropower projects greater than 50 MW) and biofuels. Importantly, BNEF investment data refer to finance secured for a particular new-build project or portfolio (there may be a lag from the time a contract is signed and finance is committed to when funds flow). This differs from the standard WEO approach, where the construction cost of projects is attributed to the year the project becomes operational. Furthermore, WEO-based figures include investment for all hydropower and are expressed in year-2009 dollars, while BNEF data are expressed in current dollars. Provided full account is taken of these methodological differences, the BNEF-based data presented in this section are particularly useful for the insights provided into investment in the short- to medium-term. On a quarterly basis, investment fell to $19 billion in the first quarter of 2009, in the middle of the financial and economic crisis (Figure 9.5). Investment went up again in the following quarters and has remained broadly stable since then, at slightly above $30 billion. It has not yet regained the record level of $41 billion in the last quarter of 2007. In the first half of 2010, investment was 21% higher than over the same period in 2009.

Europe leads global investment in renewable energy, while China rose to second place in 2009, overtaking the United States (Figure 9.6). Although global investment remained broadly unchanged in 2009, there were significant differences between regions. Investment went down in most regions, but the general drop was offset by a very large increase, more than 50%, in China. The most severe drop was in the United States, where investment fell to less than half the 2008 level. US financial institutions were hit hard by the crisis and credit became short. The loss of tax equity investors5 (despite an extension of the production tax credit to 2012 and its conversion into a grant) also contributed to the collapse in investment. In addition, domestic gas prices fell from $8.35 per million British thermal units (MBtu) in 2008 to $4.12 per MBtu in 2009, which made renewable electricity projects even less attractive to investors. Investment fell less dramatically in Europe, by around 10%, owing to substantial government intervention, which facilitated lending from institutions such as the European Investment Bank.6 Furthermore, feed-in tariffs, the main support mechanism for renewables in Europe, make renewable projects relatively more attractive to lenders, as generation leads to guaranteed revenues.

China, Europe and the United States account for most of the investment in renewables worldwide. Their combined share has been close to 80% in recent years. Outside these areas, Brazil has invested substantially in renewables in recent years, the level rising to $12.8 billion in 2008, but falling to $7.8 billion in 2009. Other countries in the American continent (outside the United States and Brazil) invested $7.4 billion in 2009. Against the general trends, investment in those countries nearly doubled between 2008 and

5. In the United States, the production tax credit — the main support mechanism for renewables at the federal level — can be used to finance new projects. Renewable energy developers can convert their prospective production tax credits into finance for their projects through the tax equity market. The number of tax equity providers fell sharply following the financial crisis (UNEP et al., 2009). Lehman Brothers was one such institution. 6. In euro terms, investment went down by about 6%.

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2009, driven mainly by Mexico and Canada. The Middle East and Africa also saw higher investment in 2009, although at $2.5 billion it is still rather limited. Investment in India reached $2.7 billion in 2009, 20% down on 2008. Most renewables investment now goes into wind power, followed by solar. Global investment in wind power reached $67.3 billion in 2009, a 14% increase over 2008 and nearly 60% of the total investment in renewables. Investment in solar power fell to $24.3 billion in 2009, having climbed to $33 billion in 2008. Significantly lower PV unit costs, resulting from an oversupply of modules, contributed to this fall. Investment in biofuels boomed over 2006-2008, but collapsed in 2009, for the reasons highlighted earlier. Relative to investment in renewables for electricity, investment in biofuels is still small.

Renewable energy projects can be financed either on the balance sheet of the company or, separately, on a project finance basis. There are significant differences in practice between regions and countries (Figure 9.7). Generally, financing renewable energy projects involves a significant share of debt. In Europe, project finance has been the predominant approach. Most renewable energy projects in Europe are supported by feed-in tariffs, which guarantee revenues. This has made project finance relatively easy to obtain. In the United States, however, most projects are financed on the balance sheet of companies. This is, again, a reflection of the type of support policies used in the country. While the production tax credit and renewables portfolio standards provide an incentive to invest in renewable energy, revenues are not guaranteed unless developers can obtain the long-term contracts often necessary to secure financing. In China, on-balance-sheet deals are the most common and are done mainly by large stateowned companies securing loans from state-owned banks. Project finance is, however, becoming more common, especially as private investors enter the renewable energy market. In all three regions, project finance deals fell sharply in 2009, as they entail greater risk to financiers. Because of the capital-intensive nature of renewable energy technologies, companies that have the resources to finance renewables on their balance sheet may, nonetheless, start looking for alternative ways to finance their projects as their spending on renewables becomes a larger proportion of capital spending. As a result of the financial crisis a shortage of credit for all purposes is expected to persist in the near term, with financing gaps in the affected areas. The International Monetary Fund (IMF) expects a credit shortfall in the Euro area of some €150 billion in 2010, with marginal improvements in 2011 (Table 9.3). In the United States, the credit shortfall is expected to be of the order of $280 billion in 2010, but the situation is expected to improve substantially in 2011, with the shortfall being reduced to $50 billion. Although there is some evidence that borrowing is now easier than in early 2009, the tight credit situation will have implications for investment in renewables in the near term. With greater competition for funds between renewables projects, the available capital is likely to be channelled towards the less risky projects in this sector. These difficulties are, hopefully, of short-term nature; additional renewables stimulus packages are expected to alleviate them. As of mid-2010, a total of $51 billion had been allocated to renewables, although most of the funding had not reached the sector at the time of writing (BNEF, 2010). Chapter 9 - How renewable energy markets are evolving

Table 9.3 z Credit projections for the United States and Euro area 2010

2011

540

900

Total credit demand

690

1 040

Credit shortfall

-150

-140

Total credit capacity

1 720

2 450

Total credit demand

2 000

2 500

-280

-50

Euro area (billion euros) Total credit capacity

United States (billion dollars)

Credit shortfall

Notes: Credit outside the financial sector. The Euro area comprises the countries of the European Union that use the Euro as their currency. Source: IMF (2010).

Who invests: the structure of the renewables industry Companies are increasingly taking note of the large growth potential in renewables and are investing more and more in renewables production (electricity or biofuels) or in the manufacturing of related equipment (notably for the production of renewables-based electricity). The largest of these companies are based mainly in Europe, the United States and China. In the renewables electricity sector, the companies involved are generally traditional electricity generators, including some of the largest electricity producers in the world. Many are active in more than one country. For example, Iberdrola, Spain’s largest energy company, is also present in the United States, France and the United Kingdom, among others, while E.ON, Germany’s largest electricity producer, and Energias de Portugal are present in the United States. Three of China’s largest electricity companies are among the top-ten renewable electricity producers (Table 9.4). China’s largest renewable electricity generators have invested in hydropower in Southeast Asia (Box 9.4).

Box 9.4 z China’s overseas investment in renewable energy Foreign investment by large Chinese power companies is mainly concentrated on hydro power in southeast Asian countries, in some cases, for example in the Mekong River Basin, in projects which could help enhance electricity supply in China through imports. The investment of China Huaneng Group in the Shweli I Hydropower Plant in Burma was the first of these projects. It started operation last year. Huadian Power International Corporation Limited has invested in the Asahan I Hydropower Project in Indonesia, which is about to start commercial operation, and in the Le Tour River Hydropower Project in Cambodia, which is scheduled to start up in 2012. Datang International

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Power Generation Co. Ltd. has invested in Stung Atay Hydropower Project in Cambodia, which is expected to be completed in 2011. China Power Investment Corporation has been granted approval to develop the hydro resource in the upper stream of the Yi river in Burma, which could have a capacity of 20 gigawatts (GW). In addition to these power companies, others, such as Sinohydro, China Gezhouba Group Co. and China National Heavy Machinery Company, are also involved. It was estimated in 2008 that, at the time, there were 16 projects in Laos and 5 projects in Cambodia in which Chinese companies were involved as investors or developers (Heinrich Böll Stiftung Cambodia et al., 2008). While in the past Chinese companies have been involved mainly as contractors in the construction phase of projects, they now invest as the main owner. Overseas investment by Chinese companies in other types of renewable energy projects is limited at the moment. There are only a few small projects involving investment in wind farms and wind equipment manufacturing. But the largest power companies, as well as smaller, private ones are seeking opportunities to invest in the solar and wind market abroad, especially in Africa.

Table 9.4 z The world’s ten largest owners of renewables-based electricity and biofuel producing facilities, as of June 2010 Electricity Company

Notes: Large hydro is not included. Country refers to location of the headquarters of the company (many are multinational). Source: Bloomberg New Energy Finance databases.

Unlike renewables-based electricity, biofuels producers are not for the most part traditional energy companies. The top-ten companies in the business are mostly US companies. Many of them (for example, Archer Daniels Midland, Louis Dreyfus Group, 290

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Cosan Limited, Sofiproteol, Bunge Ltd and Cargill) are involved in the agricultural commodities business. Most are active in more than one country. While no large oil companies appear in the top-ten, their interest in biofuels is growing: Royal Dutch Shell and Brazil’s Cosan signed an agreement in August 2010 to form a joint venture in Brazil. On the manufacturing side, the market for wind turbines and photovoltaics is becoming global and the industry is rapidly changing. While wind turbine manufacturing is still dominated by European companies, China has emerged as a major manufacturer, with three companies among the world’s largest (Table 9.5). This is quite different from the market in 2000, when, outside Europe, only India’s Suzlon and the United States-based GE Energy were among the top-ten manufacturers (WEO-2009). Table 9.5 z Global market shares of top-ten wind turbine manufacturers 2008 Manufacturer

2009

Country

Market share

Manufacturer

Country

Market share

Vestas

Denmark

19.8%

Vestas

Denmark

12.5%

GE Energy

United States

18.6%

GE Energy

United States

12.4%

Gamesa

Spain

12.0%

Sinovel

China

9.2%

Enercon

Germany

10.0%

Enercon

Germany

8.5%

Suzlon

India

9.0%

Goldwind

China

7.2%

Siemens

Germany

6.9%

Gamesa

Spain

6.7%

Sinovel

China

5.0%

Dongfang

China

6.5%

Acciona

Spain

4.6%

Suzlon

India

6.4%

Goldwind

China

4.0%

Siemens

Germany

5.9%

Nordex

Germany

3.8%

Repower

Germany

3.4%

Note: Country refers to location of the headquarters of the company. Sources: BTM Consult (2009); BTM Consult (2010).

The market for solar cells is dominated by Asian companies from China, Japan and Chinese Taipei, although the United States remains a significant producer (Table 9.6). Germany is the only European country with significant solar cell production. Many of the main players are becoming multinational, with manufacturing facilities in several countries.

Significant merger and acquisition (M&A) activity has taken place in the renewables sector in recent years, although there was a nearly 30% drop in 2009 (Table 9.7). The most important transactions now are in the solar manufacturing sector — exceeding $6 billion in 2009 — which accounted for nearly half of the total M&A activity in the production of renewables and related equipment manufacturing.7 7. The discussion of M&As in this section does not include large hydropower, as explained in Box 9.3. It should be noted, however, that substantial M&As are taking place in the hydropower sector. M&As in hydropower are estimated to have reached about $15 billion in 2009 (PWC, 2010).

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Much of this activity has taken place in China, where smaller companies have suffered from an overcapacity among panel manufacturers and a plunge in global silicon prices (KPMG, 2010).

Outlook for investment In the New Policies Scenario, over 2010-2035 cumulative investment in renewables for electricity generation totals $5.7 trillion (in 2009 dollars), reverting to the normal WEO conventions and including large-hydro (Box 9.3). Another $335 billion goes into biofuels. China makes the largest investment in renewables electricity, followed by the European Union. The largest investment in biofuels is in the United States (Figure 9.8). 292

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To meet the requirements of the New Policies Scenario, annual investment in 2035 needs to increase several times above current levels. There are several signs that the renewables sector will, indeed, continue to grow in the future, as discussed above: the persistent rise in investment up to 2008, the relative resilience of the sector on a global scale in 2009 despite the financial economic crisis, the involvement of a multitude of companies and increasingly of households, and intense M&A activity. But several challenges remain, both from the investors’ and the lenders’ perspectives. As noted, government intervention is the main driver for the development of renewable energy. Investment will be forthcoming only if incentives are sufficient to guarantee a commercial return to power generators and biofuels producers. Further, government policies will have to address the specific risks associated with the different technologies (for example, the higher investor risk for new technologies than for mature or almost mature technologies). For industrial users, most investment in renewables is likely to be driven by the need to meet imposed emissions-reduction requirements. The potential to displace fossil fuels is large in many sectors of industry. Household investment in renewables is growing as consumers respond to environmental concerns and, in some cases, realise that they can obtain significant savings on their energy bills by switching to renewables. However, few countries incentivise renewables for heat, despite the large potential. To maximise their effect, policies to support renewables need to be clear, stable and well-publicised.

Figure 9.8 z Cumulative investment in renewables by type and selected country/region in the New Policies Scenario, 2010-2035 Electricity

Financiers will take into account a variety of risks when considering lending to renewables, which typically include country and financial risk, policy and regulatory risk, technical and project specific risk, and market risk (UNEP et al. 2009). While such risks exist for all energy projects, some of the risks are higher for renewables. Policy and technology risks, in particular, can be significantly higher. Chapter 9 - How renewable energy markets are evolving

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The challenges are likely to be the greatest in developing countries (Box 9.5). In the New Policies Scenario, these countries, excluding China, will need a total of $1.6 trillion in 2010-2035. In many developing countries, however, domestic capital markets do not have enough liquidity to cover these needs, so external financing will be necessary. Greater private sector participation is also likely to be necessary.

Box 9.5 z Some key issues in financing renewables in developing countries A number of financial barriers continue to constrain the development of renewable energy in developing countries (Parthan et al., 2010). While their exact nature and the degree of influence varies between countries, the perception of risk, the lack of scale and higher transaction costs are all important. A number of multi-lateral, bi-lateral and national initiatives have been taken to assist in the removal of these barriers, in partnership with developing countries. Some of the conclusions to be drawn are: z In general, significant local financing is available in most developing

countries for renewable energy investments, partially from institutions such as local development banks, commercial banks and agricultural development banks and, in other cases, from specialised low-carbon energy finance institutions. Generally missing are risk mitigation instruments and retail-level institutions for channelling the finance. z Guarantee funds can be used effectively in the early stages of market

development, but they need to be replenished and sustained over the long run. Insurance products covering performance risk and the risk associated with weather fluctuations are in short supply. z Despite prevailing misconceptions, both urban/peri-urban and rural poor

people already pay significant sums for energy, both in absolute terms but, particularly, as a proportion of their total incomes. Providing renewable energy services to the poor is not just a matter for non-profit organisations but is already, in many cases, a profitable business on a commercial basis. z Micro-finance can play a major role in the development of markets for small

renewable energy systems and devices, but the achievements have so far been in market niches. The three critical factors to be addressed in order to scale-up the role of micro-finance in renewable energy are the management of transaction costs, credit risk management, and the availability of lowcost long-term financial resources at the wholesale level. z The capacity of the finance and banking sector to evaluate and manage

renewable energy projects in the commercial, development and agricultural sectors needs to be expanded.

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z Supporting the establishment of dedicated finance facilities is a high-risk

undertaking for development agencies. The risks can be reduced by ensuring that the projects entering the pipeline meet adequate tests of credibility, that there is evidence of serious commitment from early stage investors, and that the promoter company has a strong past track-record.

Costs of renewables The cost of government support mechanisms The application of renewable energy on a large scale depends on government incentives to make the unit costs competitive with conventional technologies. Incentives for renewable energy take many forms, from support to developers to support to customers. These incentives are generally described in this chapter as government support or support mechanisms, neutral terms which express no judgement on the argument that there is an economic case for intervention on the grounds that renewables are unduly disadvantaged in the energy market as it is presently constituted. Defining government support is an uncertain undertaking. For the purposes of this analysis, government support to renewables is defined as any government measure that encourages the production or consumption of renewable energy sources. It can take a variety of forms, including mandates or portfolio standards, green certificates, feedin-tariffs and premiums, and production, consumption and investment tax incentives. Some of these means of supporting renewables fall into the category of subsidies to consumers or producers (see Chapter 19 for a definition of subsidies). Other support mechanisms may not necessarily be a subsidy. The overall value of support to renewables is calculated here as the price paid to renewable energy producers for their output over and above the prevailing market price (or reference price), or as the incentive (price premium or tax incentives), multiplied by the quantity of energy subsidised.8 In the case of electricity generation, the reference price is assumed to be the wholesale electricity price for all sources except solar photovoltaics in buildings, where the electricity end-user price is used. In the case of biofuels for transport, the reference price is assumed to be equal to the ex-tax price of the fuel at the pump that is substituted by ethanol and biodiesel.9

Measured this way, worldwide government support to renewables amounted to $57 billion in 2009 — up from $44 billion in 2008 and $41 billion in 2007 (Figure 9.9). The 29% increase in 2009 was in part due to a sharp drop in reference prices in 2009. In the New Policies Scenario, support grows throughout the period, reaching $205 billion 8. See chapters 10 and 12 for details of the methodology. For a discussion of subsidies to fossil-fuel consumption, see Chapter 19. 9. These calculations do not take into account spending on research and development, nor grants to households to induce them to buy renewable-energy based installations, nor spending by governments on advertising advocating the adoption of renewable energy.

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by 2035.10 It amounted to 0.08% of global GDP on average over the period 2007-2009, and grows to 0.17% of global GDP in 2035. Cumulatively, support totals $4 trillion in 2010-2035. Of this, 63% goes to renewable electricity and 37% to biofuels. While total support grows over time, it decreases on a per unit basis, both for electricity and biofuels, as technology costs come down.

Billion dollars (2009)

Figure 9.9 z Annual global support for renewables in the New Policies Scenario 210

Biofuels

180

Renewables-based electricity

150 120 90 60 30 0

2007

2008

2009

2015

2020

2025

2030

2035

Given the array of benefits arising from greater use of renewables (not reflected in market prices) and the imperfections in the market pricing of other fuels, a degree of government support to these fuels and related technologies can be justified. Yet, governments need to ensure that the chosen mechanisms are cost effective, match the requirements of the particular technology involved and maintain competitive pressures between the different renewable technologies.

In addition to providing support as defined above, governments are engaged in substantial continuing efforts in research and development (R&D) to bring the costs of renewable energy technologies down and to improve their performance. Some of these technologies, such as hydropower, onshore wind and biomass are mature or almost mature and do not require significant additional spending on R&D, although R&D is still needed for better wind forecasting and working variable generation into the power supply system. Photovoltaics and concentrating solar power, though commercially available, depend for their widespread diffusion on further supportive policy measures. Total spending on R&D (using BNEF data, as explained in Box 9.3) reached $5.6 billion in 2009. Corporate R&D accounted for over 70% of this spending in recent years, but fell by 17% in 2009. Government spending rose in that year, more than compensating for the drop in corporate R&D and accounting for 45% of the total spending on R&D. More than half of current R&D spending goes into solar technologies (Figure 9.10). Spending is also significant in wind power-related research (both onshore and offshore 10. In the 450 Scenario, support for renewables reaches $300 billion in 2035 (see Chapter 13).

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technologies) and in advanced biofuels. These three areas together absorbed 84% of total spending in 2009. Spending on R&D in the New Policies Scenario needs to rise significantly above present levels. Figure 9.10 z Global spending on research and development in renewable energy by technology, 2009 4%

4% 1%

7%

Solar Wind Biofuels Total $5.6 billion

15%

Biomass & waste 53%

Geothermal Marine Small hydro

16%

9

Source: Bloomberg New Energy Finance databases.

Integration costs of variable renewables Provision also needs to be made to integrate variable renewables for electricity generation into the supply system. The additional network costs are estimated to be $13 billion in Europe and $11 billion in the United States in 2035. Cost effective ways to compensate for variable renewables supply do exist: a more integrated approach is required, planning simultaneously for the expansion of renewables production and the expansion of networks in order to keep costs low. In general, integration over large areas is more cost-effective.

Benefits of renewables The main benefits of renewables — and the reasons for government support — are that they reduce CO2 emissions (where used instead of fossil fuels) and reduce dependence on imported fuels, notably oil and gas. In the New Policies Scenario, renewables use cuts emissions by an extra 2 gigatonnes (Gt) CO2 in 2035, relative to the Current Policies Scenario.11 This is almost 30% of the total CO2 savings in the New Policies Scenario (Figure 9.11). Most of these savings come from the power sector, where renewables displace coal and gas. Additional savings also arise from biofuels displacing oil in transport and from biomass and solar displacing fossil fuels for heat production. Renewables also reduce gas imports for power generation and oil imports for transport. Oil importing countries see their bills reduced by about $130 billion in 2035. Some reductions in gas import bills also arise, although they are much smaller. 11. The benefits of renewables are much larger in the 450 Scenario. See chapters 13 and 14.

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Renewable energy has already created over three million jobs worldwide, of which about half are in the biofuels industry (REN21, 2010). The support for renewables included in many recent financial stimulus packages is expected to bring further employment benefits. Between 2008 and 2035, electricity generated by renewables increases three-fold, biofuels by over four times and heat from renewables by a factor of two in the New Policies Scenario, implying increases in gross employment creation (though not necessarily pro rata). Renewables are believed to create more jobs than fossil fuels per unit of output (UNEP, 2008; Fraunhofer Institute et al., 2009; Greenpeace and EREC, 2010). Renewable energy has created many medium- to high-skilled jobs, particularly in the solar and wind sectors. It also helps create jobs in rural areas. However, the terms of employment there are not always favourable — currently, the bulk of biofuels jobs are found at sugar cane and palm oil plantations, where wages are low, working conditions often extremely poor and workers enjoy few rights (UNEP, 2008). Renewables help reduce local pollution, such as sulphur dioxide (SO2) and nitrogen oxides (NOx) released from fossil fuels. In the New Policies Scenario, renewables reduce pollution by 4 million tonnes (Mt) SO2 and 3 Mt NOx in 2035. Other potential benefits of renewables include: moderating effects on rising fossil-fuel prices and reduced vulnerability to price variability; greater long-term energy supply security through supply diversification; reduced adaptation costs; trade benefits for countries that manufacture and export-related equipment; and benefits for rural development. By contrast, some renewable energy technologies may have adverse impacts that need to be addressed, such as land use, visual impacts or water consumption.12 Figure 9.11 z Contribution of renewables to the global emission and oil-import bill savings in 2035 in the New Policies Scenario vis-à-vis the Current Policies Scenario 35% 30% 25% 20% 15% 10% 5% 0%

Note: Shares in total CO2, SO2 and NOx emission savings and in total oil import bill reductions attributed to renewables in the New Policies Scenario, relative to the Current Policies Scenario.

12. See, for example, a discussion of the environmental co-impacts of emerging energy technologies in IEA, 2010b.

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Characteristics of renewable energy Hydropower Hydropower exploits the potential energy of water by converting it into electricity, produced either in run-of-river plants or reservoirs. Hydro power can be exploited in almost all parts of the world. It is the most mature renewable energy technology. In the OECD countries the most suitable sites, especially for large hydro, have already been developed, but there is still a large potential for small-scale developments. Large potential for hydro generation still exists in Asia, Latin America and Africa. Hydro reservoirs can be operated flexibly and therefore, especially where pumped storage is available, can meet sudden fluctuations in power demand. Depending on the volume of the reservoirs and the electrical capacity of the dam relative to the total system, some hydro plants can be operated as base load, while others serve as peaking plants. There are large differences in observed full load hours in hydro plants across the world. Hydro developments are environmentally and socially controversial. Close attention needs to be paid to minimising the negative effects on surrounding ecosystems and to water availability and other consequences downstream. Moreover, hydro reservoirs require careful design and management in order to avoid possible emissions of methane.

Biomass Biomass energy is energy produced from organic material grown, collected or harvested for energy use. At present, biomass is the only renewable energy source that can be used for electricity production, heat production and transport. The range of technologies exploiting biomass resources is very wide and the choice of technology depends not only on final use, but also on the nature of the biomass feedstock. The biomass resource can be estimated, based on the land available for dedicated crops and the available forestry and agricultural residues and waste. The main constraints on biomass exploitation are the availability of land for crops and water use (see Spotlight in this chapter and Chapter 12).

Solar energy is by far the largest energy resource available on earth. Three different technologies contribute to the capture and application of solar energy: solar photovoltaics (PV) and concentrating solar power (CSP) to provide electricity, and solar heating and cooling to provide directly usable heat (or cooling). Solar photovoltaic systems convert direct and diffused solar radiation into electricity through a photovoltaic process using semi-conductor devices. PV systems can be developed anywhere in the world on suitable land and on buildings. PV technology is also very modular, which means that systems can be installed close to centres of demand. It represents a very suitable option for off-grid electrification. Like wind, Chapter 9 - How renewable energy markets are evolving

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solar PV is a variable source of power and its integration into the grid could present a challenge for system operators where it is used on a large scale. On the other hand, peak production occurs during the day, typically coinciding, in hot regions, with peak electricity demand, often driven by air conditioning loads. Concentrating solar power (CSP) systems are designed to produce high-temperature heat for electricity generation or for co-generation of electricity and heat. CSP systems are capable only of exploiting direct normal irradiation, which is the energy received directly from the Sun (i.e. not scattered by the atmosphere) on a surface tracked perpendicular to the sun’s rays. Areas suitable for CSP development are those with strong sunshine and clear skies, usually arid or semi arid areas. CSP is a proven technology (see Box 10.1 in Chapter 10), first commercialised in the 1980s in the United States, which has seen more widespread use in recent years. CSP technology opens up the possibility of thermal energy storage, as well as hybrid designs, for example with natural gas co-firing. CSP plants, if equipped with sufficient storage capacity, could provide base-load power. Solar thermal collectors produce heat derived from solar radiation by heating a fluid circulated through a collector. Like PV panels, they are able to exploit both direct and diffused light and therefore can be installed anywhere in the world. The collectors produce relatively low temperature heat, suitable for space heating and hot water production in buildings and some lower temperature industrial applications. Solar thermal heat is not always available when domestic heat is needed (e.g. insolation is low in winter when space heat demand is the highest) and therefore solar thermal collectors have relatively limited potential to replace other sources of heat, at least until inter-seasonal storage becomes affordable. The potential for industrial heat from solar is virtually untapped for the moment.

Wind power The kinetic energy of wind is exploited in wind turbines for electricity generation. Wind speeds suitable for electricity generation range from four metres per second to 25 metres per second. These are attainable practically all over the world, with the exception of some equatorial regions. Wind power is exploited not only onshore but also off-shore, where wind speeds are higher and the wind is typically available more regularly and for longer periods of time. The depth of water and distance from centres of demand onshore are major factors influencing the siting of off-shore developments. The availability of land enjoying suitable wind conditions is one constraint. Moreover, wind is a variable source of power: output rises and falls as wind strength fluctuates. This variability poses a challenge when integrating wind power into grids, especially once wind becomes a major component of the total system.

Geothermal energy Geothermal energy is the energy available as heat extracted from the earth, usually in the form of hot water or steam. It can be exploited for power generation or for direct heat use. Geothermal resources of moderate or high temperature are suitable for 300

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power generation. High-temperature geothermal resources can be found typically in areas near plate boundaries or rift zones. Geothermal energy for electricity production is already exploited in a few areas of the world, while a more widespread but costlier potential exists, using moderate temperature geothermal power. Geothermal power plants typically serve as a source of base-load power. Geothermal plants can have a long lifetime, but exploited geothermal reservoirs require constant management. Combined heat and power geothermal plants are more economical, where there is suitable heat demand. A barrier for further development exists where high-temperature geothermal sources are distant from demand centres. Where the temperature level is too low for power production, geothermal heat resources can be exploited for direct use in district heating systems and for industrial and agricultural purposes, where local markets exist. Sources of low temperature geothermal heat are found all over the world.

Marine energy technologies exploit the kinetic energy of the tides, waves and currents of the sea, as well as temperature and salinity gradients, for the generation of electricity. The resource is, in principle, unlimited and exists in all world regions, but it is exploitable in practice only at sites that are close to demand centres and where, at the same time, damage to local ecosystems can be contained. Marine technologies are the least developed of the renewable energy technologies. Some marine technologies, namely those exploiting tides, have variable output, though this has the advantage of being predictable.

z The prospects for renewables-based electricity generation hinge critically on

government policies to encourage their development. Worldwide, the share of renewables in electricity supply increases from 19% in 2008 to 32% in 2035 in the New Policies Scenario; it reaches only 23% in the Current Policies Scenario, but 45% in the 450 Scenario. In all three scenarios, rising fossil-fuel prices and declining costs make renewables more competitive with conventional technologies. z In the New Policies Scenario, renewables-based electricity generation triples

between 2008 and 2035, reaching almost the same level as coal-fired generation by 2035. The increase comes primarily from wind and hydropower. In 2035, renewables supply 41% of total electricity in the European Union, 27% in China and 25% in the United States. Worldwide, cumulative investment of almost $6 trillion (in year-2009 dollars) is needed over 2010-2035, close to 60% of total investment in power plants. China’s investment ($1.4 trillion) exceeds that of the European Union ($1.2 trillion) and the United States ($0.8 trillion). z The share of electricity generation from variable renewables (such as wind

and solar power) is set to increase considerably, imposing additional costs on power systems. In the New Policies Scenario, integration costs amount to $16 per MWh in Europe and $17 per MWh in the United States in 2035. Generation and network planning will have to reconcile the characteristics of the new technologies with the need to maintain supply reliability. z Government support for renewables-based electricity generation reached

$37 billion in 2009 and is projected to approach $140 billion by 2035 (in year2009 dollars) in the New Policies Scenario. Support per unit of generation falls over time, as the production costs of renewables fall, reaching a global average of $23 per MWh by 2035, down from $55 per MWh in 2009. z The quality of its solar resource and its large uninhabited areas make the Middle

East and North Africa region ideal for large-scale development of concentrating solar power, costing $100 to $135 per MWh in the New Policies Scenario in 2035. Solar power could be exported to Europe (at transmission costs of $20 to $50 per MWh) and/or to countries in sub-Saharan Africa.

from 3 800 TWh in 2008 to 14 500 TWh in 2035; its share in total output increases from 19% to 45%. Cumulative investment in renewables for electricity generation over the period 2010-2035 amounts to $7.9 trillion.

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Outlook for renewables-based electricity generation Recent trends and prospects to 2035 The prospects for electricity production from renewable energy sources in the coming decades hinge critically on government policies to encourage their development and deployment. Renewables supplied almost 3 800 terawatt-hours (TWh) of electricity worldwide in 2008, 19% of total electricity production. That share has changed only marginally since 2000. In 2008, 85% of renewables-based electricity came from hydropower. The share of other renewable energy sources combined — biomass, solar, wind, geothermal and marine power — both in total electricity and in renewablesbased generation, has been rising slowly, but constantly, in recent years; their share in total electricity generation rose from 2% in 2000 to 3% in 2008, while their share in renewables-based generation rose from 9% to 15%. While hydropower has been the dominant renewable source of electricity for over a century, the strong growth recently in new technologies — particularly wind power and solar photovoltaics (PV) — has created expectations among policy makers and the industry alike that these technologies will make a major contribution to meeting growing electricity needs in the near future. While power from renewables has been growing over the past decade, in absolute terms this growth pales beside the scale of the increase in fossil-fuel based generation. Globally, electricity from renewable energy sources increased by almost 900 TWh between 2000 and 2008, but at the same time coal-fired generation increased by about 2 300 TWh and gas-fired generation by 1 600 TWh (Figure 10.1). In the OECD region, generation based on renewables increased more than that based on coal over the same period, but much less than natural gas generation. In non-OECD countries, the increase in electricity generation from renewables was slightly lower than the corresponding increase from gas, but much lower than that from coal.

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and rising fossil-fuel prices. But the pace of this increase varies widely across the three scenarios presented in this Outlook, according to the degree of government support. Worldwide, electricity based on renewable energy (including hydropower) is projected to increase from about 3 800 TWh in 2008 to about 11 200 TWh in 2035 in the New Policies Scenario; it rises less rapidly to less than 8 900 TWh in the Current Policies Scenario, but much more rapidly, to over 14 500 TWh, in the 450 Scenario (Figure 10.2). The share of renewables in total electricity generation rises from 19% in 2008 to 23%, 32% and 45% in the three scenarios respectively by 2035. In the Current Policies Scenario, renewable energy meets 28% of incremental electricity demand between 2008 and 2035. This share rises to almost 50% in the New Policies Scenario and 90% in the 450 Scenario.

The share of hydropower in total electricity generation declines in the Current Policies Scenario, from 16% to 13%. It remains broadly unchanged in the New Policies Scenario and increases from 16% to 19% in the 450 Scenario. The shares of all other renewable energy sources increase in all three scenarios. Electricity generation from biomass, wind, solar, geothermal and marine power, grouped together, increases significantly more than hydropower.

In the New Policies Scenario, renewables-based electricity generation triples between 2008 and 2035 and in absolute terms catches up with coal-fired generation by the end of the projection period (11 200 TWh). For most renewables-based technologies and in most regions, direct government incentives are the main driver of growth rather than carbon markets in the New Policies Scenario. While electricity generation from hydropower remains dominant over the Outlook period, other renewable sources collectively grow faster. By 2035, electricity generation from wind, biomass, solar, geothermal and marine energy reaches around 5 600 TWh, more than hydropower in that year. The increase in renewable electricity generation between 2008 and 2035 is derived primarily from wind and hydropower, which contribute 36% and 31% of the additional demand respectively (Figure 10.3). Chapter 10 - Renewables for electricity

Hydropower increases from 3 200 TWh to about 5 500 TWh in 2035 and installed capacity from 945 gigawatts (GW) to 1 600 GW. The share of hydropower in total generation remains constant at around 16% throughout the Outlook period. Most of the increase in hydropower occurs in non-OECD countries, where the remaining potential is highest, although development continues in OECD areas, notably in Canada, the European Union (EU) and Turkey. Hydropower sees significant growth in non-OECD Asia, where it grows from 830 TWh to almost 2 200 TWh. A total of 111 GW is now under construction (out of 168 GW worldwide), of which about 80 GW are in China, 15 GW in India and 7.5 GW in Vietnam (WEC, 2010). Hydropower also grows significantly in Latin America, where it is already the most important source of electricity. Another 16 GW are under construction in this region. Africa’s unexploited potential is very large, but progress in developing it is expected to be slow. Ten GW are now under construction across the continent. In the New Policies Scenario, hydropower continues to grow in Africa, but at a slower rate than in Asia and Latin America. Wind power (both onshore and offshore) is projected to supply 8% of global electricity in 2035, up from just 1% in 2008. Electricity generation from wind farms increases by a factor of 13 between 2008 and 2035 and installed capacity increases from 120 GW to over 1 000 GW. This continues the strong trend seen in the past decade. In 2009, a total of 38 GW was added worldwide, of which about 14 GW was in China and 10 GW each in the European Union and the United States (GWEC, 2010). These three regions see the largest increases over the Outlook period and account for 70% of the global installed wind capacity in 2035.

While most wind power is expected to come from onshore wind farms, offshore wind installations are likely to provide a growing share. In 2008, offshore wind capacity was 1.5 GW. In the New Policies Scenario it reaches almost 180 GW in 2035 as the technology improves, costs are reduced and the current difficulties in obtaining finance dissipate. Electricity produced from solar photovoltaics increases from 12 TWh in 2008 to 630 TWh in 2035, around 2% of global electricity. Installed PV capacity increases from 15 GW in 2008 (and an estimated 23 GW in 2009) to 410 GW in 2035. A little more than 306

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half of this is projected to be installed in buildings, meeting around 4% of their demand for electricity, while the remainder is for large-scale generation. Some PV will also be used in rural electrification projects. Over 160 GW of PV, 40% of the world total in 2035, is projected to be installed in non-OECD Asia, notably in China and India. Box 10.1 z Enhancements to the renewables-based power-generation module in WEO-2010 The renewables module, covering capacity additions and investments, electricity generation and heat production from renewable sources, has been overhauled and improved for this year’s Outlook, allowing for more detailed and complex modelling, and tighter integration into the power generation component of the IEA World Energy Model (WEM). Government support mechanisms that encourage the development and deployment of renewable technologies are also modelled in greater detail, allowing the additional support needed for each source to become competitive to be calculated. A full review of the potential for all renewable energy sources was undertaken for this analysis, with up to 16 technologies per region incorporated into the model. The model also takes into account expected technical developments and dynamic global learning, as well as the technical and non-technical barriers that in some countries may create obstacles to the full exploitation of the potentials considered. How renewables compete with other fuels in the power-generation mix, the electricity dispatch and the electricity wholesale and end-user prices have been enhanced.

Concentrating solar power plants produce 340 TWh of electricity in 2035, from less than 1 TWh in 2008. Installed concentrating solar power (CSP) capacity increases from 1.4 GW to over 90 GW. CSP technologies have evolved rapidly over the past few years and several advanced technology systems are now being installed, mainly in the United States and Spain. CSP is a key component in India’s Solar Mission. Box 10.2 discusses the main trends in CSP technology. Geothermal power increases from 65 TWh to about 280 TWh, mainly in the United States, Indonesia and south-east Asia (notably the Philippines). These are the regions with the greatest potential as they are located around the Pacific “ring of fire”. Geothermal installed capacity increases from 11 GW to over 40 GW.

Marine power, which comprises technologies that convert tidal and wave energy to electricity, increases less than other renewables technologies. This is because wave technologies are still in their infancy, requiring much further research, and because the locations in which tidal power can be used are limited. Marine power increases to some 60 TWh in 2035 and installed capacity to 17 GW. The share of renewables in electricity generation increases in all regions except in Brazil, which has already extensively developed its hydropower resources. Nonetheless, the share of renewables in electricity generation in Brazil remains one of the highest in the world. In 2035, the share of renewables by region ranges from about one-fifth Chapter 10 - Renewables for electricity

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to over two-thirds of total electricity (Figure 10.4). In the European Union, renewables supply 30% of electricity in 2020 (to meet the European Union’s overall target of 20% renewables in its total energy mix in 2020) and this share rises to 41% in 2035, up from 17% in 2008. Figure 10.4 z Share of renewables in total electricity generation by type and region in the New Policies Scenario Hydro

The first large CSP plants were constructed in the United States in the 1980s. Driven by technology improvements and industry initiatives in the United States, Spain and North Africa, CSP has recently gained a lot of momentum and public attention. There are four types of CSP technology: parabolic trough systems using parabolic reflectors, which concentrate solar radiation onto a receiver pipe and heat up an absorber medium; linear Fresnel collectors, operating on the same principle but using flat mirrors; power tower systems, where several sun-tracking mirrors (heliostats) focus sunlight onto a receiver at the top of a tower for steam generation; and parabolic dish systems, which use a parabolic-shaped point focus concentrator in the form of a dish. At present, most of the projects in operation or under construction are parabolic trough systems. These are mostly located in Spain and the United States.

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Further technology improvements and cost reductions are important, especially in the mirrors/reflectors, which account for around 20-40% of the overall capital costs, depending on the plant design. Power tower technologies are considered to have significant potential in this respect, with potential cost reductions for the heliostat on the order of a factor of two to three. Even more fundamental to the economics of CSP is increasing its availability, through the integration of storage (e.g. molten salt). While this significantly increases the upfront investment costs, for example due to the need for a storage tank and more reflector area, it can be more than offset by the value of the increased hours of operation per day. Provision of back-up capacity is an alternative solution. The design of CSP stations is complex and today is still done project-byproject, given that the technology is not yet mature. Constraints to be considered include land and water availability, proximity to load centres and environmental constraints, such as safeguarding protected species in desert areas. It is widely accepted that, to achieve an adequate return, CSP is ideally located in areas with annual direct normal irradiation (DNI) in excess of 2 000 kilowatt-hours per square metre per year (kWh/m2/year). Site selection and CSP design is a complex task which needs to consider the DNI on a daily basis and dispatchability. In the United States, the share of renewables in total electricity generation increases from 9% in 2008 to 25% in 2035. This increase is driven by both federal and state-level incentives. Renewables increase despite strong competition from gas-fired generation, which remains very competitive in the United States owing to the abundant domestic supply of unconventional gas (see Chapter 5). Synergies also exist between gas and renewables, as gas can compensate for the irregularity of variable renewables. In China, the share of renewables grows from 17% to 27%. China now has the largest installed hydropower capacity in the world. By 2035, China has the largest PV capacity in the world and the second-largest wind power capacity, just behind the European Union.

The generating costs of renewables technologies per unit of output are projected to continue to fall over the projection period (Figure 10.5). The main reason is increased deployment, which accelerates technological progress and increases the economies of scale in manufacturing the associated equipment. The costs of the more mature technologies, including geothermal and onshore wind power, are assumed to fall the least. The costs of hydropower remain broadly unchanged. The assumed technology learning rates used in this study are presented in Table 10.1.1 They express our best judgement, based on recent research, and are assumed to be the same across the three scenarios.

1. Learning rates are used to represent the reductions that occur in technology costs as cumulative deployment increases. A learning rate of 5% implies that the investment cost of a technology would be expected to fall by 5% with every doubling of cumulative installed capacity.

Investment needs In the New Policies Scenario, cumulative investment in renewables-based electricity generation worldwide amounts to $5.7 trillion (in year-2009 dollars) over the period 2010-2035, close to 60% of the total investment in power plants (Table 10.2 and Figure 10.6). Totalling $1.4 trillion, China’s investment exceeds that of the European Union ($1.2 trillion) or the United States ($0.8 trillion). Renewables account for a large 310

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share of total investment in power-generation plant in most regions; for example, 82% in Brazil and 71% in the European Union. Investing in renewables will pose additional financing problems, particularly in developing countries (see Chapter 9). Table 10.2 z Investment in renewables-based electricity generation by technology in the New Policies Scenario ($2009 billion) 2010-2020

The $5.7 trillion that is invested worldwide in renewables-based generation in the New Policies Scenario would deliver almost 2 800 GW of gross renewables capacity (i.e. including the replacement of existing facilities). More investment goes into wind power than any other renewable source, including hydropower (Figure 10.7). A total of $1.8 trillion is spent to build over 1 200 GW of wind power (including replacement of existing facilities). Investment in hydropower totals $1.7 trillion while investment in PV is also significant, exceeding $1 trillion over the whole projection period. Chapter 10 - Renewables for electricity

Box 10.3 z Renewables for electricity in the 450 Scenario In the 450 Scenario, global renewables-based electricity generation is projected to grow from 3 800 TWh in 2008 to just over 14 500 TWh in 2035; its share in total output increases from 19% to 45% (see Chapter 13). By 2035, electricity generation from renewables by far exceeds generation from all fossil fuels combined. Renewables supply over 50% of the European Union’s electricity in 2035, up from 17% in 2008 and one of the biggest increases in the world. While direct incentives continue to play a key role in the development of renewables in this scenario, carbon markets are increasingly a key driver. Hydropower remains the largest source of renewables-based electricity: its share increases from 16% to 19%. The largest increase in terms of market share is in wind power, which supplies 13% of electricity worldwide in 2035, up from just 1% in 2008. Biomass supplies 6% of total electricity in 2035, solar PV 4% and CSP 3%. Cumulative investment in renewables for electricity generation over the period 2010-2035 amounts to $7.9 trillion, 65% of total investment in electricityproducing facilities and nearly 40% more than in the New Policies Scenario.

Government support2 for renewables is becoming widespread. In early 2010, over 100 countries had some type of target, measure or programme to support renewables — almost double the number in 2005 (REN21, 2010). Policies focusing on electricity are far more common than policies for biofuels and even more so than for heat. 2. The term support covers all types of government policies and measures that seek to encourage the development and deployment of renewables, including, but not limited to, subsidies to production and consumption. A precise definition of subsidies is provided in Chapter 19.

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Support for renewables electricity generation can be provided at the investment phase or at the operational level, or both. Investment tax credits and loan guarantees fall into the first category. The main support mechanisms at the operational level include feed-in tariffs, green certificates, premiums and production tax credits. The main categories of support measures, along with examples of countries that use them, are shown in Table 10.3. No support mechanism can be singled out as the best; each has its advantages and disadvantages. It is important to concentrate on the most costeffective policies and, where competitive markets exist, on policies that use the strength of such markets. Table 10.3 z Classification of support mechanisms for renewables-based electricity Type of incentive

Feed-in tariffs

Most EU countries; some states and few cities in the United States; China (national system from 2010) ; Japan (only for households); South Africa; Brazil; Australia (some provinces); India (certain states)

Premiums

Denmark; Spain gives the possibility to choose between feed-in tariffs and premiums

Green certificates

United States (state level); United Kingdom; Italy; Japan; India (from October 2010); Australia

Quotas/Portfolio Standards

European Union; United States (more than half of the states + Washington D.C.); China; Japan; India; Australia; South Africa; Brazil

The 2009 EU directive on renewables set an overall binding target for 2020 to achieve a 20% share of renewables in gross final energy consumption (across electricity, heat and transport fuels). The directive set targets for each country, which then has to develop a national action plan to meet them. The directive does not specify a target for electricity generation from renewables.3 Most countries in the European Union 3. The European Commission estimates that in order to meet the overall target, around 33% of electricity must come from renewables (CEC, 2009). Some industry sources estimate that this share could be even higher, at around 40%.

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(21 out of 27) use differentiated (i.e. technology-specific) feed-in tariffs or premiums to support renewables (Canton and Johannesson Lindén, 2010). In most cases, these are time-limited (i.e. available for a fixed period of time) and are updated regularly. A few countries use green certificates and tenders. United States The most significant recent development in the United States is the passage of the American Recovery and Reinvestment Act (ARRA) in February 2009. ARRA provides new funding at the federal level, loan guarantees and tax credits for renewables and for energy efficiency (US DOE/EIA, 2009). The United States is now considering a federal renewable electricity (or portfolio) standard in several legislative proposals. These would require power companies to obtain an increasing share (reaching 15% to 25% in different proposals) of retail electricity to be from renewable energy sources. The main support mechanisms at the federal level are the production tax credit (for wind, biomass, geothermal, hydro and marine power) and the investment tax credit (mainly for PV). These are complemented by federal loan programmes, such as loan guarantees or clean renewable energy bonds. Several states now have renewables portfolio standards (mandatory or not) and offer incentives. Japan In mid-2009, Japan enacted new legislation to support the development of renewables, nuclear power and energy efficiency (Law on the Promotion of the Use of Non-fossil Energy Sources and Effective Use of Fossil Energy Source Materials by Energy Suppliers; Amendment of the Act on the Promotion of the Development and Introduction of Alternative Energy). Based on these laws, the government started providing feed-in tariffs for PV in buildings in November 2009, along with investment grants, loans and tax reductions. In June 2010, the government revised its Basic Energy Plan, which set the target for zero-emission power (nuclear and renewables) at 50% of total generation in 2020 and 70% in 2030, compared with 34% now.

Japan has had a Renewables Portfolio Standard (RPS) in place since 2003. The current RPS runs until 2014, with a target of producing 16 TWh from solar, wind, biomass, small hydro or geothermal power. Green certificates are the main support mechanism to achieve the targets set in the RPS. The Ministry of Economy, Trade and Industry (METI) proposed in July 2010 to expand feed-in tariffs to include PV for power companies, wind power (including small-scale generation), small hydro (less than 30 megawatts [MW]) geothermal and biomass. A unique tariff of around 15 to 20 yen per kWh is proposed for all sources except PV for a period of 15 to 20 years; for PV the tariff would be higher, but for a period of ten years. This new scheme would replace the current RPS. Australia In June 2010, Australia passed legislation to extend and amend its mandatory renewable energy target for electricity. The original scheme ran until 2010 but was extended to 2020, with the objective of achieving 20% of electricity from renewables. The new 314

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target is expected to add a further 45 TWh of renewables-based electricity by 2020. The existing scheme will be split into two as of 2011: the small-scale renewable energy scheme and the large-scale renewable energy target. Renewable energy certificates have been in use since 2001 and are expected to remain the main mechanism for achieving the 2020 target. China China’s most important renewable policy framework remains the Renewable Energy Law (REL), enacted in 2005. REL stipulates that grid operators must accept renewable energy power at a price higher than that of conventional generation. The Chinese government has since formulated detailed implementation rules, clarifying the levels, stages and support schemes for the development of different renewable energy technologies. A target of increasing the renewable energy share in primary energy to 15% by 2020 was set in 2009. Experts estimate that this target could increase wind, solar and biomass power generation capacity to 150 GW, 20 GW and 30 GW respectively by 2020. The government is now organising detailed surveys of renewable energy resources to provide more reliable development information, expecting that this will help the understanding of risk and encourage investors. The government is also promoting the construction of a grid to connect resource-rich areas in the west and the south to demand centres in the east and centre of the country. The development of wind power is supported by feed-in tariffs, which recently replaced a bidding system. There are four levels of feed-in tariffs, depending on the resource. For on-grid solar power, the bidding system is still in place. The government covers part of the investment cost of building integrated PV projects. Off-grid renewable power projects are funded through the Township Electrification Programme. India In January 2010, the Indian government launched the Jawaharlal Nehru National Solar Mission, which aims to install 20 GW of solar power (including PV, CSP and solar lanterns) by 2022. The Solar Mission targets both large- and small-scale generation, including for rural electrification (about 400 million people in India still lack access to electricity, see Chapter 8). A three-phase roadmap has been laid out, with interim targets for the development of solar power. India launched a feed-in tariff system in 2009, to support various renewable energy technologies, and is considering introducing renewable energy certificates. In the absence of a national renewable energy incentive, 18 out of 29 Indian states have implemented renewable energy quotas and introduced preferential tariffs.

Brazil In Brazil, capacity tenders have now replaced the PROINFA programme, which had been in place since 2004. Large hydropower is supported by a separate programme. The National Climate Change Plan, approved in 2008, provides for an increase of electricity from renewables, including greater use of hydropower (34 GW of hydropower to be added over the period 2007-2016, the current Ten Year Plan period), of wind and sugar cane bagasse and greater use of PV (on- and off-grid). Chapter 10 - Renewables for electricity

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South Africa The Renewable Energy Framework sets a target to produce 10 TWh from renewables by 2013, 60% of which would come from electricity generation and the remainder from solar water heaters. A feed-in tariff scheme was set up in 2009 to help meet the 2013 target. The scheme obliges ESKOM (the national power company) to purchase renewable energy from qualifying generators.

Quantifying government support for renewables Most renewable technologies used to produce electricity are more expensive per kWh today than conventional power technologies. As a result, intervention to increase the use of renewables-based generation raises the cost of power generation, except in the few cases where renewables-based systems are already fully competitive (and, so, in principle, do not require any type of support). In most cases, the additional costs of renewables are passed on to the final consumer. Methodology In this section, we quantify the total monetary value of government support for renewables-based electricity generation worldwide. The analysis covers all support programmes and measures that we have been able to identify, and all major countries and regions (which, taken together, now account for over 99% of world renewables-based electricity generation from wind, PV, geothermal and biomass). Projected additions of small hydropower capacity are included, but existing capacity is not. Large hydropower is not included, as it is assumed that it does not, in most cases, need or receive support.

Table 10.4 z Government support schemes for renewables-based electricity generation and quantification method Support scheme

Description

How support is quantified

Feed-in tariffs (FITs)

FITs are granted to operators for the renewable electricity they feed into the grid. They take the form of a fixed price per MWh, which reflects the cost of the technology.

(FIT — wholesale electricity price) x renewable energy generated

Production tax credit (PTC)

Direct reduction in tax liability.

PTC x renewable energy generated

Investment tax credit (ITC)

Direct reduction in tax liability.

ITC x capital investment in renewables over the year

Green certificates (GC)

A green certificate is a tradable commodity proving the production and the use of a certain amount of renewable energy.

Annual average price of GC x amount of GC issued

Premiums

Premiums are a sort of bonus and are paid to the producers on top of the electricity price (market-driven or regulated).

Premium x renewable energy generated

For the purposes of this study, support for renewables electricity generation has been defined as any incentive provided by governments in order to promote the deployment and application of renewable energy (see Chapter 9). These are generally offered as 316

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part of policies to address climate change and to improve security of supply. Examples of such incentives are feed-in tariffs, green certificates, premiums and tax credits. Some are direct cash subsidies to producers or consumers, but others have a cost or value which is more complex to pin down (see Chapter 19). Recognising the limitations of the exercise, the main objective of the analysis is to seek to measure the total monetary value of the premium paid for the output of renewables-based electricity, compared with the price paid for electricity generated in other ways. For instance, with feed-in tariff mechanisms, a fixed price is paid to renewable generators for each MWh produced and supplied to the grid. The feed-in price, generally set by the government, reflects the cost of the technology and is set at a level higher than the spot price of electricity, so as to reward renewables-based electricity generators. The support given to renewable generators is, therefore, the difference between the feed-in tariff and the market price for electricity at the point of delivery. Only the additional payment above the market price is considered as support in the analysis presented here. The analysis is not fully comprehensive or definitive. The value of some forms of support, such as direct and indirect funding for research and development into innovative projects/ technologies, grants and loan guarantees, has not been captured. On this basis, global government support for wind-, geothermal-, PV- and biomassbased electricity generation is calculated to have reached $26.6 billion in 2007 (in year-2009 dollars) (Figure 10.8). Support fell slightly to $26 billion in 2008, although generation increased by 13%. The drop in support resulted from the sharp increase in wholesale electricity prices in most countries (following the fossil-fuel price hikes), which diminished the premium per unit of output paid to the renewable electricity generators. Support grew to $37 billion in 2009, almost 43% more than in 2008. The volume of electricity produced from PV, biomass, geothermal and wind combined grew by 13%, a much lower rate than the cost of support (although there were significant differences by technology). Conversely to 2008, the main reason for the significantly higher support in 2009 was the drop in wholesale electricity prices in that year. Other factors explaining the increase include changes in policies, higher quota obligations,

Billion dollars (2009)

Figure 10.8 z Global government support for renewables-based electricity generation by technology 140

Note: Other renewables include small hydro, geothermal and marine power.

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greater generation output and a significant increase in electricity generation from PV, which has higher support relative to wind power or biomass. Our analysis shows that global support for PV exceeded $7 billion in 2009, representing 20% of the total spending in that year against a 3% share in the electricity produced from renewables receiving government support. Total future support for renewables rises to nearly $140 billion by 2035 in the New Policies Scenario. Cumulative support over 2010-2035 reaches $2.5 trillion. The pattern of support differs considerably by technology. For onshore wind power, which is relatively close to being competitive with non-renewable sources in several countries and where learning will usefully reduce costs over the Outlook period, the total cost of support diminishes over time, from $16 billion in 2009 to $4 billion in 2035, even though electricity output from onshore wind farms increases by a factor of ten over the same period. As a result, support costs per unit of onshore wind power generation fall to a global average of $2 per MWh by 2035 in the New Policies Scenario, down from $52 per MWh in 2009 (Figure 10.9). For other technologies, including PV and biomass, technological improvements also serve to drive down unit costs, but this cost reduction does not compensate for the growth in their deployment. As a result, global support rises from $7 billion in 2009 to $43 billion in 2035 for PV and from $13 billion to $60 billion for biomass, although in both cases the cost of support per unit of renewable electricity generated falls over the Outlook period. Across all renewables receiving support, the cost of support falls from around $55 per MWh in 2009 to $23 per MWh in 2035.

In several countries, onshore wind becomes fully competitive with conventional generation by the end of the period in the New Policies Scenario. In the United States, for example, as a result of a rising electricity prices and falling technology costs, onshore wind power becomes competitive by the late 2020s. In the European 318

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Union onshore wind power becomes competitive earlier, around 2020. Similarly, PV in buildings becomes competitive in some regions, such as Japan and the European Union, by the mid-2020s, despite the overall growth in the costs of global support for PV over the period.

S P O T L I G H T

Will recent cuts in incentives for photovoltaics really harm the industry? Strong government support has led to a boom in solar PV in recent years. Global PV capacity rose to 23 GW in 2009, from about 7 GW three years earlier. Growth was particularly strong in the European Union, where PV capacity reached almost 17 GW, nearly three-quarters of the global total, owing to generous feed-in tariffs. As a result, the total of PV government support increased rapidly in Europe in the past couple of years. At the same time, the price of PV installations decreased in the aftermath of the financial crisis. Some EU governments have now embarked on tariff cuts, causing some consternation in the industry that the cuts will be severe and affect the growth in PV. In July, Germany — the largest PV market in the world — decided to cut tariffs by between 11% and 16%, starting in October 2010, with somewhat lower cuts in the period July-September 2010. In July 2010, Italy also passed legislation to cut tariffs by 20% on average. In both countries, the cuts were lower than originally planned. In Spain, a Royal Decree currently under discussion proposes an adjustment through a limitation on the number of hours that qualify to receive the premium. Belgium, France and Greece are also cutting tariffs.

Although these PV tariff cuts may appear at first sight to represent a weakening of government support for renewables, they are consistent with the declared intentions of most countries regularly to review and adjust feed-in tariffs, taking into account technology costs and market conditions, so as to avoid windfall profits and encourage the industry to become competitive and self-reliant. Our analysis of government support shows that the total support cost for PV in Europe grew much faster in the past few years than support for less expensive technologies, such as wind, and is set to continue to increase over the next two decades in the New Policies Scenario. The annual support cost for PV in that region begins to fall only towards the end of the Outlook period.

There are marked differences in the pattern of support for renewables between regions. The European Union is currently the region with the highest level of support for renewables, having spent $23 billion in 2009. A combination of a rising wholesale electricity price, falling technology costs and the particular features of Europe’s renewable technology mix means that the European Union’s annual support for renewables grows slowly over the decade to 2020, peaking around 2020 at almost $25 billion. It then declines gradually to a little over $21 billion by 2035. Japan shows Chapter 10 - Renewables for electricity

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a similar pattern, with support peaking in the early 2020s. Annual support levels in the European Union and Japan in the past have been volatile, due to the nature of the feed-in tariffs, which guarantee a steady income to producers of electricity from renewables regardless of changes in market electricity prices. In the United States, government support grew steadily over the period 2007-2009, hitting $9.6 billion in 2009. This will double to over $20 billion by the mid-2020s, and then begin to fall gradually. China’s level of support over the period 2007-2009 was low compared with the European Union and the United States, but grows significantly, from around $1 billion in 2009 to almost $16 billion in 2020 and $38 billion by 2035 (Figure 10.10). Figure 10.10 z Global government support for renewables-based electricity generation by region in the New Policies Scenario 2007 European Union

The degree to which the additional cost of renewables that results from government support is passed through to end-users in each country depends on the details of the support mechanisms in each country. When the additional cost for renewable sources is in the form of premiums or green certificates, then the cost is passed on directly to the end-user, resulting in higher electricity tariffs. Feed-in tariffs are also usually paid for by electricity consumers. Tax-credits as a form of support result in unchanged or lower prices for the end-user, with the additional cost carried by governments. Greater support for renewables, resulting in their increased deployment, leads to lower investment costs for renewables in the long term and ultimately to a reduction in the government support needed per unit of electricity produced. In the New Policies Scenario, the total support needed for the deployment of renewables is $1.3 trillion in the OECD countries over the Outlook period. The pattern of support is different in each region. In the United States, support grows as a proportion of the wholesale price until the mid-2020s, when it begins to decline, due to the falling cost of renewables and a growing wholesale price. A similar pattern applies to the European Union and Japan, but with support per MWh of electricity generation peaking earlier (around 2020) in 320

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both regions. In China support grows throughout the period, mainly due to a wholesale price that grows far more slowly than in OECD countries as there is no carbon pricing in the Chinese power sector in the New Policies Scenario. Over the period, this support corresponds to an addition of 5% on average to the wholesale electricity price in the OECD countries. This figure is 7% in the European Union, 5% in the United States and 3% in Japan, reflecting the level of penetration of renewables in the different countries and the level of the wholesale prices (Figure 10.11).

Dollars per MWh (2009)

Figure 10.11 z Average wholesale electricity prices and impact of renewable support in selected OECD regions in the New Policies Scenario, 2010-2035 120

Additional cost of renewables

100

Wholesale price

80 60 40

10

20 0

United States

European Union

Japan

Network integration of variable renewables Overview The output of certain renewable electricity generation technologies, such as wind, marine, solar PV or run-of-river hydropower, is variable in nature, i.e. it fluctuates depending on the availability of their primary energy source, such as wind, sun, or water, which cannot be controlled, although generation based on these resources can be curtailed when necessary.4 Growing shares of variable renewables will require modifications to the operation of the system and market, and eventually additional flexible reserves, in order to ensure system security is not impaired. There will also be a need for rules to address who carries these extra costs and how they are distributed among the different power and grid companies involved. All these need to be in place from the outset, when planning for a large-scale increase in the share of renewables.

In the New Policies Scenario, the share of electricity generation from variable renewables increases considerably in most regions over the projection period (Figure 10.12). Across the world, that share rises from just 1% in 2008 to 10% by 2035, 4. All generation sources are variable to an extent. However, the variability of certain renewable energy sources is significantly higher, more frequent and less predictable in nature, and generally increases with the level of their penetration in the system.

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but with significant variation among regions. The share is highest now in the European Union, at almost 4%, and the EU share remains the highest in the world throughout the projection period, reaching 22% in 2035. It reaches over 10% in the United States (12%) and Canada (11%). In Australia and New Zealand, the share is 10%, while China and India reach 9%. It is 7% in South Africa and Japan. Figure 10.12 z Shares of variable renewables in total electricity generation by region in the New Policies Scenario 2008

European Union United States Canada World OECD Oceania China India South Africa Japan Brazil Russia

2035

0%

5%

10%

15%

20%

25%

Variable generation has implications for total capacity, the design of the network and the balancing of the power system.5 All can be addressed through greater generation flexibility and strengthening of transmission networks. Managed demand response and storage offer additional mitigation options. In order to maintain supply reliability, traditional methods of planning and operating generation and networks have to evolve to take into account the characteristics of these new technologies.

Among the various cost components of renewable energy generation, integration costs are perhaps the most uncertain because there is no universally accepted methodology for estimating these costs. Experts do not always agree on what constitutes an additional cost and whether it should be attributed to renewables. For example, all studies include balancing costs within integration costs, while only some also account for interconnection costs and fewer still consider adequacy costs (for definitions, see below).6 However, an estimate of integration costs, along with information on the capital costs of generation and operating expenses (relatively 5. For a more comprehensive analysis of flexibility in grid systems and the major enablers of and obstacles to integrating renewables, please refer to the forthcoming results from the IEA on the Grid Integration of Variable Renewables (GIVAR) project (IEA, forthcoming). 6. See, for example: CAISO (2007); DCENR and DETI (2008); DENA (2005); EnerNex Corporation (2006); EnerNex Corporation (2010); EWEA (2005); GE Energy (2008 and 2010); Holttinen et al. (2009); Mills et al. (2009); NERC (2009); Transpower Stromübertragungs-Gmbh (2010); VTT Technical Research Centre of Finland (2009); and UK ERC (2006).

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easier to obtain), is necessary to give policy makers an estimate of the total costs resulting from the adoption of renewable technologies. A better understanding of integration issues can help guide efforts to reduce these costs in the future, especially important as they become more significant with increasing penetration levels. The various costs associated with integrating increased levels of variable generation into the system can be grouped into three major categories:  Network (interconnection costs): Renewable resources may be located far

from load centres and the existing transmission network. The construction of high-voltage transmission lines may be necessary to link such resources to the existing grid. Interconnection costs are incurred primarily as large upfront capital investments.  Balancing costs: Matching electric power supply with demand is critical to power

systems. The addition of variable renewables to the generation system increases the need for ancillary services, a term often used to refer collectively to the resources required to meet system balancing needs. These costs are mainly incurred as operational costs, on a short-term basis (seconds to days).  Capacity adequacy costs: These arise from the need to maintain sufficient

capacity in the grid to handle peak loads. In order to maintain system security, an adequate amount of backup generation capacity is required, which varies, depending upon the capacity value of the variable source (Box 10.4). This results in the attribution of additional capacity costs to variable generation.

The technical challenges and the associated integration costs vary considerably among various regions, mainly due to the different characteristics of variable renewable generation in different geographical locations, differences in the demand and generation mix of the incumbent systems, dissimilar technical (security) standards and commercial frameworks, and different ways of quantifying impacts and costs. Therefore integration costs are generally calculated on a caseby-case basis. Despite the difficulties in assessing integration costs, we attempt in the following section to arrive at broad cost estimates for the United States and the European Union, the only two regions for which detailed cost studies have been conducted. Most of the studies focus on onshore wind power, while studies on solar are just beginning to emerge. Our estimates cover onshore and offshore wind power, CSP and PV for large-scale generation. If technology-specific costs are not available, we have used costs based on onshore wind power, because we can infer from current studies that there are similarities between onshore wind and these other technologies. We have not included distributed PV in our estimates, since we estimate that the cost impact of small dispersed systems in buildings is likely to be very small. Marine technologies are not included either, as their integration costs have not been studied and, even in 2035, they account for a very small percentage of total generation. Chapter 10 - Renewables for electricity

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Figure 10.13 z Power generation system flexibility by region in the New Policies Scenario, 2035 Limited flexibility

Notes: Shares are based on installed capacity. Variable capacity includes wind, solar PV, small hydro and marine power. Flexible capacity includes large hydro, combined-cycle gas turbines (without carbon capture and storage) and open-cycle gas turbines. Limited flexibility capacity includes nuclear power and coal (with and without carbon capture and storage) and combined-cycle gas turbines with carbon capture and storage. In the European Union, the level of system flexibility may vary between countries. In France, nuclear power plants are capable of load-following.

Box 10.4 z Capacity value of variable renewables The contribution of variable renewables to the adequacy of a system is often significantly lower (per MW of installed capacity) than that attributable to other energy options. Because only a fraction of total capacity has a high probability of running consistently, variable renewables have limited capacity value.

The capacity value depends on the renewable energy source and varies across different systems. It generally declines with higher penetration, eventually approaching saturation. Major factors affecting the capacity value of variable generation include the correlation between the timing of demand and variable generation output (for example, PV generation has a higher capacity value in countries where peak demand occurs during daytime, as in Japan or Spain, and wind has a higher capacity value in Denmark, because it is more generally available at the time of peak demand in the evening) and the locational diversity of the variable resource (i.e. a wind resource with larger distances between wind farms will generally have a higher capacity value than the same magnitude of resource concentrated in a small area; or PV in buildings has a higher capacity value than large-scale PV generation, which is more concentrated). A high frequency of zero or very low generation availability during peak demand periods of the year can also severely impact the capacity value of variable renewables. The capacity value of a variable source, e.g. wind generation, has been found to differ significantly according to whether the system is dominated by thermal plants or thermal and flexible hydro power plants. Systems having a significant

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share of flexible hydro plant, as in Norway and New Zealand, can offer capacity support to variable generation by time shifting the available energy to meet peak demand. More generally, a system with high shares of flexible capacity and interconnections can enhance the capacity value of wind. Figure 10.13 illustrates the degree of power generation flexibility for major regions in 2035.

Interconnection costs The location of renewable energy plants is largely determined by the geographical location of rich natural resources, which are often away from load centers and the existing transmission network. For example, in the United States, there is signifcant wind potential in sparsely populated states, such as North Dakota, Wyoming and Montana. In Europe, there is significant wind potential in the North Sea. Utilising these natural resources requires the construction of transmission lines to transport energy from the generation sites to load centres. In the New Policies Scenario, we estimate interconnection costs to be of the order of $9 per MWh in 2035 in the European Union and $12 per MWh in the United States. These estimates are based on the Eastern Wind Integration and Transmission Study (EWITS), which focuses on a large area in the United States (EnerNex Corporation, 2010). The cost estimates given apply to integration in both the United States and Europe. The study shows transmission costs decreasing from $15 per MWh at 6% wind penetration levels to $9 per MWh at 20% wind penetration and $7 per MWh at 30% wind penetration. The decrease in unit cost with increasing penetration can be attributed to the increasing use of higher capacity transmission technology with lower costs per kW-mile, such as High Voltage Direct Current (HVDC) lines. Balancing costs

Balancing costs can differ widely depending on factors ranging from the mix of existing generation plants in a region to the diversity of the renewable resources achieved through geographic spread or technological mix. Norway has low integration costs, due to the significant hydropower resources in their grid that greatly mitigate the balancing costs for wind. Similarly, regional studies conducted for the Eastern United States and Europe (the European Wind Integration Study, EWIS) (Transpower StromübertragungsGmbh, 2010) show lower costs than those estimated for the UK (Energy Research Center, ERC study) (UK ERC, 2006), probably because of differences in the geographical spread of resources. We estimate balancing costs for onshore wind power to be of the order of $3.5 per MWh in Europe and $2.5 per MWh in the United States. Studies conducted by the Colorado Public Service Company (CPSCo) show concentrated solar power (CSP) balancing costs to be approximately half of those for onshore wind, all other thinbgs being equal. Also, using insights from EWITS, one may estimate that the balancing costs of offshore wind could be 75% of those for onshore wind. Chapter 10 - Renewables for electricity

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Adequacy costs Adequacy costs for variable renewables arise from the lower contribution made by new renewable generation capacity to the maintenance of reliable supply in a system, compared to that provided by conventional energy sources. Actual adequacy costs incurred in a given grid system can vary widely and usually need to be evaluated on a case-by-case basis. In general, adequacy costs can become manifest as investment costs for building new generation capacity or as lost revenue for existing capacity becuase of the reduced load factor for conventional plants. A primary determinant of adequacy costs is capacity value. Most recent studies show that capacity values for wind energy range from 10% to 25% at up to 30% wind penetration. Fewer studies have analysed the capacity value attributed to solar technologies. According to the Western Wind and Solar Integration Study (GE Energy, 2010), at low penetration levels, capacity values are around 30% for PV and 90% for CSP. In many systems, PV energy tends to be much better aligned with peak load than wind energy, leading to higher capacity values. Comparatively, CSP commands much higher capacity values for mainly two reasons. First, CSP is usually better aligned with peak load, because it is built only in areas with high direct normal irradiance (DNI), unlike PV. Second, CSP plants can include storage that contributes to avoidance of disruptions in supply and allows output to peak later in the day, when peak loads are more likely to occur. We assume adequacy costs to be of the order of $4 per MWh for onshore and offshore wind in both the United States and Europe. CSP adequacy costs are assumed to be zero, because most CSP is assumed to be equipped with storage. Summary of integration costs Based on the estimates above, total integration costs in 2035 in the New Policies Scenario would add, on average $16 per MWh in Europe and $17 per MWh in the United States. The total cost of integration in that year is put at $13 billion in the European Union and $11 billion in the United States. The assumed costs per MWh and total costs are summarised in Table 10.5. Table 10.5 z Integration costs of variable renewables in the European Union and the United States in the New Policies Scenario, 2035 Interconnection

Source: IEA analysis. Notes: Costs have been calculated for onshore and offshore wind, CSP and large scale PV. Distributed PV costs are assumed to be zero. Adequacy costs for large PV in Europe have not been calculated as there are no relative studies and costs cannot be inferred from studies analysing costs in the United States. Balancing costs are assumed to be 50% of the costs of onshore wind for CSP and large PV and 75% for offshore wind.

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Dealing with the variability of renewables Forecasting Improved forecasting of the output of variable generation in the coming few minutes or hours results in better utilisation of these sources and reduces the need for an operating reserve to mitigate their unpredictability. Lower operating reserve requirements enhance the capacity of the system to integrate variable generation and reduce efficiency losses and the use of high marginal cost plant. The arrival of large weather fronts, e.g. storms, can lead to the loss of wind generation over the entire area covered by the weather front for the duration of the storm. More accurate longer term forecasting of such phenomena contributes to bringing alternative plants online in a timely manner, but, due to the infrequent nature of these weather phenomena, the impact on balancing costs is not substantial. Demand response The importance of managing demand response could rise in the future.7 The implications go well beyond the issues related to the variability of renewables, but they are also important in that area. Demand response in the form of redistribution of load (e.g. when load is moved from peak to off-peak periods) can help mitigate the capacity problem associated with variable generation, firming up the capacity value of variable generation and so reducing the need for peaking plant. Demand response can reduce balancing costs because it increases the efficiency of the system operation by reducing the required operating reserve and the associated costs. Transmission related integration costs can also be reduced if demand is able to follow variable supply. Maximising the use of renewable generation locally reduces the need for interconnections to export surplus variable generation. The value of demand response in this context will depend upon the volume of surplus generation and the level of energy storage capability available. Smart grids A smart grid facilitates increased integration of variable renewables into the power system to increase flexibility. The smart grid makes use of enhanced system information and control to allow operational changes, such as intra-hour renewable dispatch (see also the discussion of smart grids in Box 7.1 in Chapter 7), which contribute to better management of the system, reducing system bottlenecks and congestion (IEA, forthcoming, c). Storage

Energy storage facilities permit energy availability to be shifted across time (typically over periods of hours) by charging up during periods of low demand and/or surplus low cost generation and discharging during high demand periods, associated with high marginal cost generation. Common storage technologies include pumped hydro, compressed air energy storage and large battery energy storage systems. 7. A new IEA report will examine the role of demand response in OECD electricity markets (IEA, forthcoming, a).

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Storage may make modest amounts of peak conventional generating capacity redundant in systems without and with variable generation. Storage facilities can also mitigate the lack of correlation between high demand and the output of variable generation, so enhancing the capacity value of the variable source. Energy storage facilities enhance system flexibility by, at least partly, decoupling fluctuating energy supply from demand. Where the building of new transmission lines is constrained, storage may offer an alternative outlet for the renewable generation produced. Currently, storage technologies have relatively high investment costs. Reducing the costs of these technologies is key to expanding the use of energy storage in the future (Inage, 2009).

Special focus: Offshore wind power Offshore wind power is still at an early stage of commercialisation. At the end of 2008, there were 1.4 GW of installed capacity, all in European countries around the North Sea, the Baltic Sea and the Irish Sea (Table 10.6). Capacity rose to 2.1 GW in 2009. In that year, Germany, Norway and — the first country outside Europe — China installed their first offshore wind farms.

Compared with onshore wind power, offshore wind is still small because of its higher cost and because many technical challenges remain. The potential for offshore wind power is, however, very large. Over the Outlook period, offshore wind capacity is projected to increase to 115 GW in 2035 in the Current Policies Scenario, 180 GW in 328

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the New Policies Scenario and nearly 340 GW in the 450 Scenario, supplying 1%, 2% and 4% of global electricity (Figure 10.14). The largest increases are in OECD Europe, OECD North America (mostly in the United States) and in China. OECD Europe remains the most important region for offshore wind power development in all scenarios. Installed capacity there rises to 48 GW in 2035 in the Current Policies Scenario, 64 GW in the New Policies Scenario and almost 100 GW in the 450 Scenario. Most of the development is expected to continue to be in Northern Europe, where the potential is very large. Offshore wind power is expected to be distributed across the region, requiring the construction of a major offshore grid to connect offshore wind farms to the mainland. In December 2009, the United Kingdom, Germany, France, Belgium, Netherlands, Luxembourg, Denmark, Sweden and Ireland launched the North Seas Countries’ Offshore Grid initiative, providing for co-operation in the development of the grid infrastructure in the North Sea. Norway endorsed the initiative in February 2010.

Investment Total investment in offshore wind power over 2010-2035 amounts to $260 billion (in 2009 dollars) in the Current Policies Scenario, $400 billion in the New Policies Scenario, and $640 billion in the 450 Scenario. In OECD Europe, investment ranges between $120 billion and $200 billion. Financing offshore wind farms is at present problematic, because financial institutions perceive the technology as risky and require a higher share of equity, compared with other renewables, notably onshore wind projects and PV. As the technology improves and bankers become more comfortable with it, lending should become easier. Until then, governments may have to play a role to facilitate investment in offshore wind power by, for example, increasing the role of multilateral lending institutions.

Technology Offshore wind turbine technology needs further development. At present, most offshore turbines are based on onshore turbine technology, modified to reflect practices and experiences in other offshore industries (IEA, 2009). The reliability of offshore turbines, which is currently lower than that of onshore wind turbines, needs to improve. More robust turbines, designed from the outset to operate in offshore conditions, need to be developed for the technology to take off. This would require — among other things — a focus on the combined effects of different loads on all parts of the wind turbine and its foundations, as the marine environment interacts with waves and currents. To date, the foundations of most offshore projects consist of a single pile driven into the seabed, called a monopile. Current monopile designs account for about a quarter of the total investment cost of an offshore wind farm. Improved foundation designs can help bring costs down. Although offshore wind turbines are currently located in shallow water areas, significant potential exists in deep waters and new designs are being developed to allow capture this potential. Floating turbines are one such design (Box 10.5). Box 10.5 z Floating wind turbines in Norway The world’s first large-scale prototype floating wind turbine — the 2.3 MW Hywind prototype — started operation in 2009 in Norway. The turbine is located 10 kilometres off the coast of Karmøy, near Stavanger, where the water depth reaches 220 metres. The project was developed by Statoil, the Norwegian oil and gas company, which has plans to invest a total of 400 million Norwegian kroner (about $65 million) in its construction and operation. An additional 59 million kroner ($10 million) is being funded by the Norwegian government.

The Hywind project consists of a 65 metre tall wind tower with an 82 metre rotor diameter. It weighs 138 tonnes. The turbine is anchored to the sea bed through a 100 metre long steel cylinder, weighing 3 000 tonnes, which contains a ballast of water and rocks. This allows the structure to move with the sea — a concept building on offshore oil and gas experience. A submarine cable connects the installation to the nearest power station onshore. The facility is now in a two year test period, until the fall of 2011. A larger project, the 10 MW Sway prototype, is planned. If the design proves to be successful, floating turbines could be used in locations further offshore, in water depths of 120 to 700 metres, where wind speeds are higher and more constant than nearer the shore. Furthermore, floating wind turbines can help overcome some of the challenges that face conventional offshore turbines located near the coast, including the visual impact and the conflict with fishing and other coastal activities.

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Special focus: Renewables in the Middle East and North Africa The countries of Middle East and North Africa (MENA) are endowed with rich oil and gas resources (in particular the Gulf Cooperation Council countries, Algeria, Egypt and Libya). They also have some of the highest solar resources in the world (Table 10.7). To date the solar resources are almost totally unexploited. While solar is the most abundant resource in all countries in the region, some also have hydropower resources (e.g. Egypt on the Nile river, Iran on its northwestern plains, Iraq and Syria in the Tigris-Euphrates basin) and wind resources (e.g. along the Red Sea and on Morocco’s Atlantic coast). The main use of renewable energy is for electricity generation, mainly from hydropower. In 2008, less than 3% of the region’s electricity came from renewables, but it was as high as 12% in Egypt, 7% in Syria, 6% in Morocco and 3.5% in Lebanon. In all other countries, the share of electricity from renewables was less than 2% or zero. The use of renewables for heat is very limited, except in Israel, where solar water heaters are used extensively in buildings. Biomass use for heat is limited, amounting to just 4.5 Mtoe in 2008. About half of this is traditional biomass and the other half is used in industry and commercial establishments. Liquid biofuels are not yet used in the region.

Note: Technical potentials based on direct normal irradiation. Resources of above 5 kWh per m2 per day (or 1 825 kWh per m2 annually) are considered as very good. Few countries in the world have resources above 7.5 kWh per m2 per day. Source: IEA analysis using data provided by the United States National Renewable Energy Laboratory.

Domestic policies and initiatives Support for renewables has grown in recent years and policies to promote renewables in the region are spreading. A growing number of countries have set targets for renewables, which are summarised in Table 10.8, along with the main programmes, measures and incentives involved. Most of the countries involved are in North Africa. Chapter 10 - Renewables for electricity

 The Masdar initiative, headed by the Abu Dhabi Future Energy Company (Masdar), is

the most prominent. Its focus is on clean energy, including renewables and cleaner fossil fuels (including energy efficiency and carbon capture and storage), with an investment target of $22 billion. Masdars’ activities span all stages of renewable energy development from research to commercialisation. The company is currently building a zero-carbon city (Masdar City) which will make extensive use of solar power. 332

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 A regional centre was created in Cairo in 2008 with the aim of promoting renewables

City for Atomic and Renewable Energy in Riyadh. There are also several intra-regional or inter-regional initiatives between MENA and Europe which relate either to energy in general (including renewables) or to renewable energy specifically. These include MEDENER (Mediterranean Energy, the Mediterranean association of national agencies for energy conservation), MEDREG (Mediterranean Regulators, the association of the Mediterranean regulators for electricity and gas), MEDELEC (Mediterranean Electricity, a group of regional electricity associations), MENAREC (the Middle East and North Africa Renewable Energy Conference, with a focus on renewables for energy and water) and MEDREP (the Mediterranean Renewable Energy Programme, which aims at providing sustainable energy to rural areas and at increasing the share of renewables in the region’s energy mix).

Outlook The use of renewable energy in total grows significantly in all three scenarios. Most of the increase comes from the electricity sector. Total electricity generation from renewables increases from 26 TWh in 2008 to 222 TWh (9% of electricity generation) in the Current Policies Scenario, to about 380 TWh (18% of electricity generation) in the New Policies Scenario and 610 TWh (33% of electricity generation) in the 450 Scenario in 2035. The share of renewables in electricity generation in 2035 increases to 26% in the Middle East and up to 58% in North Africa (Table 10.9). These projections assume only domestic use of renewables.

Investment in renewables electricity generation in MENA amounts to $155 billion (in 2009 dollars) over the period 2010-2035 in the Current Policies Scenario, increasing to $260 billion in the New Policies Scenario and just over $400 billion in the 450 Scenario. Current electricity tariff systems in several countries in the region do not pass full costs on to consumers. Governments are now assuming the extra costs of renewables. Some projects could benefit from the Clean Development Mechanism. Greater involvement of the private sector, to which countries in the region and more particularly in North Africa are becoming more and more open, is likely in the future. Policies to support greater use of solar water heaters yield useful results: the share of solar energy in heat demand in buildings stays at around 1% in the Current Policies Scenario and grows to 2% in the New Policies Scenario and 3% in the 450 Scenario in 2035. The absence of policies relating to industrial energy use keeps demand for modern biomass in industry low in all scenarios. For the same reason, demand for biofuels stays close to nil in the Current Policies and New Policies Scenarios, though biofuels supply 6% of road transport demand in 2035 in the 450 Scenario, mainly through biofuels imports to the Middle East, where governments are assumed to participate in a global agreement to improve the efficiency of road transport. Chapter 10 - Renewables for electricity

Large-scale development of renewables in MENA The strong interest in European countries in renewable energy has revived European interest in MENA’s vast solar resources and has given rise to two major initiatives: the government-led Mediterranean Solar Plan (MSP) and the private sector-led Desertec industrial initiative Dii.

The objective of the MSP, launched in 2008, is to promote a sustainable energy future in the Mediterranean region.8 The plan proposes to increase the use of solar and other forms of renewable energy, to improve energy efficiency, to develop electricity grid interconnections9 and to stimulate technology transfer to developing countries in the region. MSP targets the development of 20 GW of renewables by 2020, of which 5 GW could be exported to Europe. Total investment would be of the order of 60 billion euros. More than 150 projects have been proposed (mostly from European developers) and about 70 have been selected. Developing interconnections between North Africa and Europe would cost another 4 to 5 billion euros. Within this framework, an industrial

8. See Guarrera et al. (2010) for a detailed description of these initiatives. 9. This objective is supported by the European Commission. Interconnecting the northern and southern shores of the Mediterranean is one of the European Union’s four major projects for developing electricity networks. The other three involve strengthening the south-east interconnections; the interconnection of the Baltic grid to other grids; and the construction of undersea cables to link North Sea and Baltic Sea wind installations.

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initiative has been set up — the Transgreen project — with the aim of co-ordinating efforts to develop such network links. Desertec was initiated by the German Association of the Club of Rome, with the vision of developing a CSP grid in MENA, connected to Europe. The Dii Desertec industrial initiative was launched in 2009 by a group of large private companies, with the aim of accelerating and implementing the Desertec concept. The focus of Dii is on solar and wind power generation from the deserts of MENA countries, both to meet local demand and for export to Europe. The ultimate objective is to produce enough power by 2050 to meet 15% of Europe’s electricity demand and a substantial proportion of the needs of producing countries. To realise this objective, Dii envisages the construction of a supergrid that would connect renewable energy resources with demand centres.

The economics of concentrating solar power How best to utilise the vast potential of solar energy is a current policy focus in many MENA countries. Export to Europe is the dominant objective of the above initiatives. CSP is currently not competitive with conventional electricity generation, but significant potential for technology improvements exists (see Box 10.2) and the pace of development will very much depend on the degree to which the adoption of CSP is supported by policy measures. To illustrate the prospects for the export of CSP-generated electricity from MENA regions to Europe, the individual cost components of CSP technologies (parabolic trough and power tower technologies) are examined in-depth below, together with the costs of transmitting electricity to Europe using high-voltage direct current (HVDC) transmission lines — the most efficient option for transmitting electricity over long distances. The cost assumptions used have additionally been reviewed by industry experts outside the IEA.

For the analysis, the maximum annual average direct normal irradiation (DNI) per day and country, as provided by the US National Renewable Energy Laboratory, have been used to identify the maximum average DNI for Northern African countries (about 7.8 kWh per m2 per day) and Middle East countries (about 6.9 kWh per m2 per day). This is an approximation, as each CSP plant will be optimised individually according to local solar resource conditions at different times of the day. However, it provides sufficient insight into the potential of the region as a whole to generate CSP electricity cost-competitively. In the New Policies Scenario by 2035, CSP electricity can be produced at costs of around $100 to $120 per MWh at good sites in Northern Africa and $110 to $135 per MWh in the Middle East (Figure 10.15). Efficient storage (assumed at a level sufficient to provide electricity for eight hours in our analysis) is important to achieving sufficiently low generating costs, as it increases the capacity value of CSP plants. Lower generating costs are feasible by further increasing the capacity value through the use of larger storage tanks or additional gas backup. However, the inclusion of storage increases investment costs significantly by 50% to 90% on a per kW basis. Chapter 10 - Renewables for electricity

Potential transmission to Europe involves additional costs for HVDC lines as well as converter stations. For the purposes of the analysis, the closest geographical connection point in the European Union relative to the exporting regions was considered, distinguishing overhead and submarine cables and their respective costs. Transmission lines are assumed to be used solely for the export of electricity from CSP and so capacity factors are comparatively modest (up to around 60%). This results in transmission costs of $20 to $40 per MWh for Northern Africa, and $30 to $50 per MWh for the Middle East. Transmitting electricity further, to central European countries, entails significant additional costs. Additional cost reductions could be achieved if the use of the cables could be increased. If capacity factors were 90%, transmission costs to the borders of the European Union could be as low as $10 to $12 per MWh. Capacity factors could be increased through the construction of additional storage and/or backup capacity using, for example, natural gas combined-cycle plants. In the New Policies Scenario, large-scale electricity from CSP in MENA countries does not become competitive with European wholesale electricity prices, but remains about 20% more expensive even in 2035 (Figure 10.16). Nevertheless, these prices are annual averages, and CSP import could be profitable at individual times of the day and year, in particular where it would be competing with other more expensive renewable electricity. The prospect of cost reductions for CSP achieved through global learning-by-doing, together with increasing wholesale electricity prices in Europe in this scenario, show that the potential is there. In Northern Africa, every country has significant solar potential in excess of 7.5 kWh per m2 per day, over an area of 220 000 square kilometres. The largest areas with such solar potential considered here are located in Algeria, followed by Egypt and Morocco. In the Middle East, only Saudi Arabia and Yemen have a solar potential similar to that of Northern African 336

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countries. The total land area available at above 7 kWh per m2 per day in the Middle East is roughly 60 000 square kilometres, of which more than one-third is located in Saudi Arabia.

Dollars per MWh (2009)

Figure 10.16 z CSP generating costs in North Africa and European wholesale electricity price in the New Policies Scenario 200

Additional policy support could further increase the competitiveness of CSP from MENA. In the 450 Scenario, where action to achieve climate stabilisation targets results in increased CSP use globally and leads to further cost reductions, CSP costs can fall to below $100 per MWh in 2035 (excluding transmission costs). At the same time, rapidly increasing CO2 prices in the European Union — in particular after 2020 — drive up wholesale electricity prices, which reach $106 per MWh in 2035. In this case, CSP from MENA would be competitive in Europe, depending on transmission costs and how much these can be lowered through increased utilisation of the cables. In summary, the quality of its solar resource and its large uninhabited areas make MENA ideal for large-scale development of solar power. But there are many challenges at the political, technical and market level that must first be overcome. For European countries, the main benefit would be cost-effective reductions in greenhouse gas emissions, using dispatchable (and thereby more reliable) renewable energy from MENA, and greater diversity of electricity supply. For MENA countries, such a largescale development of solar power would both help meet their rapid growing electricity demand and expand their own transmission networks to provide reliable electricity access to all. Many of the poorer countries in the region are struggling to attract foreign capital for developing their own power sector and cross-border co-operation with Europe in a mutually beneficial manner would certainly help. Large-scale CSP development could also create jobs in the region in the power plants and, potentially, in manufacturing solar plants or components. It could also generate export revenues from selling electricity. The success of large-scale CSP development in MENA, entailing exports to Europe, will largely depend on public acceptance in the exporting countries. A situation where CSP Chapter 10 - Renewables for electricity

electricity is committed solely to export would be unacceptable in MENA countries. Since poorer countries of the sub-Saharan region are among those with the least access to modern energy services (see Chapter 8), public acceptance (also in Europe) of large-scale CSP electricity export from MENA might be greater if the benefits of such development could be seen to be shared with neighbouring countries. One way to achieve this would be to extend grids so as to provide not only for export to Europe but also to sub-Saharan Africa, where additional distribution grid capacity is required to make use of it.

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CHAPTER 11

RENEWABLES FOR HEAT The sleeping giant? H

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S

z Heat — defined as the consumption of non-electrical energy for producing heat

for use in stationary applications — accounted for 47% of global final energy consumption in 2008 (transport and electricity accounted for the rest). In the buildings sector, heat is needed for cooking, and water and space heating. In the industry sector, the heat produced in boilers and co-generation facilities is used for process applications. Worldwide, traditional and modern renewables together supplied 27% of total demand for heat, or 1 059 Mtoe, in 2008. This increases to nearly 1 400 Mtoe in 2035 in the New Policies Scenario, meeting 29% of total demand for heat. The share of modern renewables in total renewables for heat grows from 29% to 48%. Demand for traditional biomass falls in non-OECD Asian and Latin American countries, but increases in sub-Saharan Africa, due to rising population and the region’s slower economic growth. Globally, the use of traditional biomass falls from 746 Mtoe in 2008 to just over 720 Mtoe in 2035 in the New Policies Scenario. Heat from modern renewables more than doubles in the New Policies Scenario, from 312 Mtoe in 2008 to over 650 Mtoe in 2035. Modern renewables account for 16% of global heat demand in 2035, up from 10% in 2008. In the OECD, most of the growth is in the European Union, the United States, Australia and New Zealand. Outside of the OECD, growth is largest in China and Brazil. Biomass remains the main source of renewables-based heat, both in industry (where the pulp and paper industry is the largest user) and in buildings. Its share in industrial energy demand increases from 11% in 2008 to 15% in 2035 in the New Policies Scenario. In the buildings sector, heat produced from modern biomass doubles over the projection period. The use of solar heat is expected to remain concentrated in buildings. In the New Policies Scenario, solar heat demand in buildings increases from 9 Mtoe in 2008 to 65 Mtoe in 2035. Most of the growth takes place in China, followed by the United States and the European Union. China is projected to remain the world’s largest user of solar water heaters. In 2008, about 80% of the world’s installed solar collector area was in China. The use of solar heat there is projected to increase from 4 Mtoe in 2008 to 18 Mtoe in 2035 in the New Policies Scenario. In the 450 Scenario, the share of modern renewables in total heat increases sharply, from 10% in 2008 to 21% in 2035. The most significant increase is in buildings, where renewables supply over one-quarter of the need for heat in 2035, up from 8% now. In industry, the share of renewables in total heat consumption grows from 11% to 18%.

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Recent trends This chapter discusses key trends in heat produced from renewable energy sources, whether it is produced on-site or delivered as a commercial service. It starts with an overview of total needs for heat, defined here as the consumption of energy sources (excluding electricity) to produce heat used in stationary applications. It then focuses on the fraction of this that comes from renewables. It sets out scenario projections of the consumption of renewable fuels for producing heat and presents in detail the results of the New Policies Scenario. This is followed by a brief discussion of the key technologies and the characteristics of government policies to promote renewables for heat. The last section takes a qualitative look at renewables for cooling (without quantitative analysis in our scenarios because data are not available). Heat is the main energy service, accounting for close to half of global final energy demand. In the buildings sector, the heat produced from gas, oil, coal or renewable energy sources provides cooking, and water and space heating services. In the industrial sector, the heat produced in boilers and co-generation facilities (along with electricity) is used for process applications. Heat is also used in agriculture, for example to heat greenhouses. Heat can be produced on-site in buildings and industrial facilities or it can be purchased on a network. The latter is termed here “commercial heat”, reflecting the delivery of heat as a commercial service; it does not refer to heat used in commercial undertakings.1 Renewables as the energy source for heat include biomass, solar and geothermal energy used to produce heat on-site in industry (including through co-generation facilities) and buildings, as well as the renewables fraction of commercial heat. Unlike renewables for the transportation and electricity sectors, in which a large number of policies exists to promote the use of biofuels and renewablesbased electricity, renewables for heat receive little policy attention today.

Demand for heat dominates final energy consumption, even when traditional biomass2 is not included (Figure 11.1). The share of heat in global final energy consumption (excluding traditional biomass) was 47% in 2008, a far higher share than that of transport (27%), electricity (17%) or non-energy use (9%). Because of the large share of heat in final energy demand, expanding the use of modern biomass, geothermal and solar energy to produce heat could make a substantial contribution to meeting climate change and energy security objectives.

1. The term commercial heat as used throughout this chapter refers solely to heat produced in a heat plant or a co-generation plant (also referred to as combined heat and power) and sold through a network to industrial facilities, households or commercial establishments (district heat). In this chapter and in Chapter 9, the definition of heat is broader than the one in Annex C, which applies to the rest of book. 2. Traditional biomass is defined as biomass consumption in the residential sector in developing countries and refers to the often unsustainable use of wood, charcoal, agricultural residues and animal dung for cooking and heating. All other biomass use is defined as modern.

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Figure 11.1 z Final energy consumption by energy service, 2008 100%

Non-energy use Transport

80%

Electricity Heat

60% 40% 20% 0% World

World excluding traditional biomass

OECD

Non-OECD

Demand for heat is, unsurprisingly, higher in colder climates; Russia and Canada, for example, have very high per-capita heat consumption (Figure 11.2).3 Demand for heat is not, however, only climate-dependent. Some warm-climate countries also have a large share of heat in total final energy consumption. In such cases, this often stems from using significant amounts of process heat in industry or heavy reliance on traditional biomass (for example, in developing countries like Indonesia). The share of heat in final demand is particularly high in China, owing mainly to its large industrial sector.

Renewable energy sources play an important role in heat supply. Worldwide, traditional biomass and modern renewables together fuelled 27% of the total demand for heat, or 1 059 million tonnes of oil equivalent (Mtoe), in 2008. Traditional biomass, including 3. Personal income is another important determinant of per-capita heat demand.

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wood, charcoal, crop residues and animal dung, accounts for the bulk of total heat supply. It is mostly used for cooking and water heating in developing countries but, in colder climates, biomass stoves also provide space heating. The use of these biomass resources is considered traditional because they are most often burned at very low efficiencies and release many pollutants that have a serious health impact. In 2008, 746 Mtoe of traditional biomass was consumed in the residential sector in developing countries, with consumption in sub-Saharan African countries accounting for 32%.4 Due to the large population of China and India and their heavy reliance on traditional biomass, these countries also account for a significant share of the global population relying on traditional biomass. Demand for traditional biomass worldwide increased by 12% between 2000 and 2008. The global use of modern renewables for producing heat reached 312 Mtoe in 2008, 10% of total demand for heat. Although the use of modern renewables for heat increased by 18% between 2000 and 2008, its share in total heat demand did not increase. At 278 Mtoe in 2008, the main modern renewable energy source for producing heat is biomass, (including wood products, such as pellets and briquettes that have been made to burn efficiently, industrial biogas and bioliquids). Solar and geothermal contributed 10 Mtoe and 5 Mtoe to heat supply in 2008; commercial heat produced from modern renewables accounted for 19 Mtoe. The share of renewable energy in total demand for heat varies widely in OECD countries (data for non-OECD countries is of low quality) (Figure 11.3). In Sweden, 63% of total heat demand in 2008 was supplied by renewables, whereas in the United Kingdom renewables contributed only 1%. Commercial heat is important in some countries, notably in Sweden, Iceland and Austria. Use of geothermal energy is considerable in Iceland and New Zealand. Greece and Austria make extensive use of solar water heaters, relative to other countries. Figure 11.3 z Share of renewables in total heat demand by type in selected OECD countries, 2008 Biomass

4. Chapter 8 provides more information on the traditional use of biomass in developing countries.

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A variety of technologies are used to produce heat from renewables: solar collectors, biomass stoves using pellets or wood, anaerobic gas digesters and co-generation plants. These technologies are discussed in more detail later in the chapter.

Outlook for renewables for heat production In the New Policies Scenario, global renewable heat demand rises from 1 059 Mtoe in 2008 to nearly 1 400 Mtoe in 2035. Traditional biomass meets the largest share of this demand, although it falls from 71% to 52% over the Outlook period. In the Current Policies Scenario, demand for renewables for heat increases to over 1 250 Mtoe in 2035, with the share of traditional biomass in total renewables for heat declining to 57% in 2035. In the 450 Scenario, demand for modern renewables for heat ratchets up to almost 1 500 Mtoe in 2035. In this scenario, the traditional use of biomass accounts for only 47% in 2035. The rest of this section presents more detailed results for renewable heat demand in the New Policies Scenario.

Traditional biomass In the New Policies Scenario, traditional biomass continues to be the main source of heat in the residential sector in many developing countries, particularly in sub-Saharan Africa.5 Nonetheless, a significant decline in the use of traditional biomass in China results in a fall in global demand from 746 Mtoe in 2008 to a little over 720 Mtoe in 2035. Reliance on traditional biomass for heat declines as incomes rise. Low-income households use a three-stone fire6 or can usually only afford a basic cookstove (which is marginally more efficient). At higher incomes, households can afford more efficient biomass cooking and heating devices or conventional stoves and the use of traditional biomass declines. While demand for traditional biomass falls in developing Asian and Latin American countries, it increases in sub-Saharan Africa on the assumption of slower economic growth.

Demand for traditional biomass climbs to almost 300 Mtoe in 2035 in Africa, mainly in sub-Saharan countries (Figure 11.4). In China, traditional biomass demand drops from some 200 Mtoe in 2008 to 120 Mtoe in 2035, as a large number of households switch to conventional stoves or modern biomass, such as biogas, for cooking. Traditional use of biomass also falls in India, from 128 Mtoe to about 120 Mtoe over the Outlook period; a steeper decline in traditional biomass demand is tempered by the “National Biomass Cookstove Initiative”, a programme that aims to improve the efficiency of cooking and heating with biomass.7

5. See Chapter 8 for an analysis of the number of people relying on the traditional use of biomass over the projection period and the health implications. 6. A three-stone fire uses three stones to support the pot and firewood is placed underneath. 7. See Box 8.6 in Chapter 8.

Modern renewables In the New Policies Scenario, global demand for modern renewables for heat more than doubles over the Outlook period, growing from 312 Mtoe in 2008 to over 650 Mtoe by 2035. By 2035, 16% of total demand for heat comes from renewables, compared with 10% in 2008. Demand for renewables increases at an annual average growth rate of 2.8% over the projection period in the New Policies Scenario, higher than the 2% annual growth rate over 2000-2008. While solar energy grows seven-fold over the projection period, from 10 Mtoe to 70 Mtoe, modern biomass continues to dominate modern renewables for heat. Geothermal production of heat on-site increases from 5 Mtoe to 26 Mtoe.

In the OECD, much of the current building stock is likely to remain in use for many decades. Most of the potential for increased penetration of modern renewables into the supply of heat for buildings, therefore, lies in retrofitting existing buildings. In developing countries, where new building growth will be very rapid, opportunities exist to install modern renewable technologies from the outset. Similarly, the industrial and service sectors experience rapid growth in developing countries, creating large opportunities for renewables. Even though industrial demand for heat declines in OECD countries over the projection period, significant opportunities still remain to replace ageing fossil-fuel based technologies with renewables. The share of modern renewables in total heat demand rises more substantially in OECD countries than non-OECD countries over the projection period, from 11% to 23%, in the New Policies Scenario (Table 11.1 and Figure 11.5). Nearly all of the increase occurs in the United States, European Union, and Australia and New Zealand, where policies to promote heat from renewable energy are expected to bear fruit. Modern renewables, mostly biomass, accounted for about one-fifth of total industrial sector heat demand in Australia and New Zealand in 2008, the highest share among OECD countries, which 344

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increases to 41% in 2035 in the New Policies Scenario. Most of the additional demand comes from industry, which accounts for 60% of the increase in renewables for heat between 2008 and 2035 in these two countries. Table 11.1 z Share of modern renewables for heat in total heat demand by region in the New Policies Scenario 2008

2020

2035

11%

15%

23%

United States

10%

16%

25%

Australia and New Zealand

18%

26%

41%

9%

10%

12%

China

1%

2%

5%

Brazil

47%

49%

50%

World

10%

12%

16%

European Union

13%

17%

26%

OECD

Non-OECD

Outside of the OECD, the share of renewables for heat in total heat demand increases from 9% in 2008 to 12% in 2035. Demand for renewables increases more in China and Brazil than elsewhere in the non-OECD group. In China, demand for modern renewables for heat increases from 6 Mtoe in 2008 to nearly 50 Mtoe in 2035, resulting mainly from growth in biomass-based industrial co-generation and even greater use of solar water heaters in buildings. Use of modern renewables for heat in Brazil rises from 36 Mtoe to more than 65 Mtoe over the Outlook period, mainly in the form of bagasse (a by-product of the sugar industry) co-generation in various industries, charcoal use in steel-making and solar heat in buildings.

Box 11.1 z Expanding the production of heat from biomass in the industry sector Roughly three-quarters of industrial energy demand arises from the production of energy-intensive commodities, such as metals, chemicals and petrochemicals, non-metallic mineral materials, and pulp and paper. Because of the high share of energy in total production costs, industrial energy efficiency levels are much higher than in the buildings and transport sectors, and the potential for further improvements is lower (Taibi et al., forthcoming). Thus, if significant carbon dioxide (CO2) reductions are to be achieved in the industrial sector, switching to renewables has to be a favoured course. Heat demand in industry falls into different temperature ranges, and so needs to be matched with the appropriate renewables-based heat technology. Solid biomass and biogas have the advantage that they can provide heat across all temperature ranges, although high temperatures cannot be achieved economically with current technologies. The industries that have significant biomass potential include chemicals and petrochemicals and cement. For chemicals and petrochemicals, successful deployment of biomass depends primarily on building biorefineries that produce a range of products. Once the logistics are in place, low-grade biomass can be procured specifically for the production of process heat. In the cement sector, waste and low-grade biomass can be used to produce heat. Overall, there is significant potential to increase the use of renewables in industry, but its development depends on government support and, in the long run, a price for greenhouse-gas emissions.

Modern biomass is used to produce process heat in the industry sector, and for space and water heating in the buildings sector. In the New Policies Scenario, global biomass use for heat increases from 278 Mtoe in 2008 to over 520 Mtoe in 2035. Industry remains the main user of modern biomass over the Outlook period; in absolute terms, its use for heat production increases from 191 Mtoe in 2008 to nearly 340 Mtoe in 2035. The pulp and paper sector is, by far, the largest industrial consumer of biomass for heat (Figure 11.6). In 2035, nearly 80% of the biomass-fed heat demand in the chemicals sector and around 80% in the paper industry arises in OECD countries. Due to its reliance on charcoal, Brazil accounts for 94% of global demand for biomass for heat in the iron and steel industry in 2035.8 Modern biomass use in buildings doubles over the projection period, from 81 Mtoe to 169 Mtoe, meeting a growing share of their energy needs.

8. For example, ArcelorMittal Bioenergetica produces charcoal from eucalyptus forestry operations. This charcoal is used to fuel iron furnaces in Juiz de Fora or to be exchanged for pig iron with local producers (Taibi et al., 2010).

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Mtoe

Figure 11.6 z Global modern biomass for heat in selected industries in the New Policies Scenario 80

Chemical & petrochemical

70

Iron & steel

60

Non-metallic minerals

50 40

Paper, pulp & printing

30 20 10 0

2008

2035

Solar energy to produce heat is used mainly in buildings. The use of solar energy for the production of heat is very small in the industry sector today (though not all of it is captured in statistics). Some uptake of solar energy for heat is projected in OECD countries, yet it still accounts for less than 1% of total global heat in the industry sector in 2035. Global solar heat demand in buildings increases from 9 Mtoe in 2008 to 65 Mtoe in 2035, growing at 7.4% per year on average, in the New Policies Scenario. Most of the growth takes place in China (alone representing 56% of non-OECD demand in 2035), followed by the United States and European Union (Figure 11.7). The United States and the European Union combined represent nearly 80% of solar heat demand in OECD countries in 2035.

Mtoe

Figure 11.7 z Solar heat consumption in the buildings sector by region in the New Policies Scenario 20

Box 11.2 z The impact of technology development on the uptake of solar for heat Higher penetration of modern renewables in heat demand will depend on technology developments related to temperature and storage. Heat demand differs by temperature levels according to the application (IEA, 2007). Water temperatures for space heating vary from 45°C (for under-floor heating) to 90°C (for heating by conventional radiators). Domestic hot water requires a temperature of 60°C, whereas industrial process heat can demand a temperature ranging from 60°C to more than 400°C. The temperature levels provided by renewable heating technologies vary from 45°C (from ground source heat pumps) to 80°C (from conventional solar thermal flat panels) and up to 400°C (from concentrating solar technologies). Biomass heat can provide all required temperature levels, whereas geothermal heat levels differ by location: they can exceed 150°C in specific areas. Conventional solar thermal panels, providing low-temperature heat up to 80°C, have considerable potential in providing industrial process heat. This is the case for the European Union, as 30% of European industrial heat demand is estimated to consist of heat below 100°C (EcoHeatCool, 2006). Several industrial processes, such as pasteurisation, sterilisation, cooking, bleaching, dyeing, preheating water and washing, require temperatures of 60°C to 90°C. Solar thermal collectors currently are used for low-temperature processes in the brewing industry. Concentrating solar power (CSP) plants, which produce electricity and heat, offer another potential avenue to expand the use of solar heat. Investments in several CSP projects, including in China, India, Morocco, Spain and the United States, are expected to stimulate development of the technology. These will also amplify its potential for applications in industrial process heat, and as heat sold on the network. In the New Policies Scenario, however, CSP is projected to be used only for the production of electricity.

Geothermal energy for heat production is used mainly in buildings. Global geothermal heat use is projected to grow from 5 Mtoe in 2008 to slightly more than 25 Mtoe in 2035. Most of the increase is in OECD countries, notably in the United States and certain countries in OECD Europe (e.g. Turkey, Iceland and Switzerland). Almost all the growth is in the buildings sector.

Commercial heat is increasingly supplied by modern renewables, their share in total commercial heat rising from 7% in 2008 to 14% in 2035. Biomass continues to account for the lion’s share of renewable energy used for commercial heat. Growth in demand for modern renewables for commercial heat is strongest in the European Union and China. Many countries in the European Union have a high share of commercial heat in overall heat demand. While northern European countries, such as Iceland, Finland, Sweden and Denmark, supply large amounts of renewable heat for their district heating systems, countries like Poland, Czech Republic, Hungary and Slovakia rely mainly on fossil-fuel based combined heat and power plants (CHP) plants, and, in some cases, considerable 348

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amounts of coal. These countries have wide scope for replacing fossil-fuelled heat by renewables-based heat. Biomass has the greatest potential and is most efficiently used in CHP plants, supplying a district heating network. Biomass combustion to produce electricity and heat in CHP plants is a mature technology and in many cases is already competitive with fossil fuels. In the New Policies Scenario, the share of modern renewables in commercial heat demand doubles in the European Union, from 17% to 34% over the Outlook period. In China, there is a switch from coal and oil to biomass for commercial heat. Modern renewables supplied just 0.5% of commercial heat in China in 2008, but this share is projected to climb to 13% by 2035. S P O T L I G H T

How big is the potential for solar water heating in China? Given China’s abundant solar resources, we project solar technologies to make an important contribution to reducing the country’s greenhouse-gas emissions, particularly in the buildings sector. In urban areas, the market share of solar water heaters in China increased from about 15% in 2001 to over 50% in 2008. Although the upfront capital cost of solar water heaters is higher than electric or gas water heaters, the average annual investment over the lifetime of the heater is considerably lower (Table 11.2). The use of solar thermal collectors in China has grown rapidly, from 15 million square kilometres (km2) of total collector area in 1998 to 135 million km2 in 2008, accounting for about 80% of the world total in that year (Weiss, 2010). China is also a major exporter of solar water heaters, with the value of exports increasing nearly six-fold from 2001 to 2007. In terms of industry development, production of solar water heaters in China increased nearly eight-fold from 1998 to 2008. Sales were 43 billion yuan ($6.3 billion) in 2008. In 2007, there were more than 3 000 manufacturers of solar water heaters in China. In the New Policies Scenario, solar energy use in buildings grows five-fold between 2008 and 2035.

Table 11.2 z Cost comparison of water heaters in China Electric water heater

Gas water heater

Solar water heater

Hot water supply (litres per day)

100

100

100

Equipment investment ($)

176

146

264

Annual operating cost ($)

73

51

0.73

Lifetime (years)

8

8

10

Average annual investment over lifetime ($)

95

82

27

Note: Cost figures have been converted to dollars from yuan, using the 2009 average annual exchange rate of $1 = 6.83 yuan. Source: REN21 (2009).

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Box 11.3 z Renewables for heat in the 450 Scenario9 In the 450 Scenario, demand for traditional biomass falls from 746 Mtoe in 2008 to just under 700 Mtoe in 2035. By contrast, demand for modern renewables increases sharply, from 312 Mtoe to nearly 800 Mtoe; its share in total heat demand increases from 10% to 21%. The most significant increase is in buildings, where demand almost quadruples over the projection period. Renewables supply over one-quarter of the heat needs in buildings in 2035, up from 8% now. This increase is underpinned by concerted government action to promote energy efficiency and renewables in buildings. In industry, the share of renewables in total demand for heat grows from 11% to 18%, with growth encouraged by cap-and-trade schemes.9 In the 450 Scenario, biomass use more than doubles, from 278 Mtoe to almost 600 Mtoe; demand for solar increases from 10 Mtoe to nearly 120 Mtoe; and geothermal use rises from 5 Mtoe to more than 40 Mtoe. Renewables supply 20% of commercial heat in 2035, a share three times higher than in 2008. Over the period 2010-2035, the incremental investment in renewables relative to the Current Policies Scenario is $680 billion.

Renewable energy technologies for heat Biomass Modern biomass combustion to produce heat is a mature technology and in many cases is competitive with fossil fuels (IEA, 2007).10 Modern on-site biomass technologies include efficient wood burning stoves, municipal solid waste (MSW) incineration, pellet boilers and biogas. Biomass is also used in CHP production, which is more efficient than production of electricity or heat alone; where the heat can be usefully employed, overall conversion efficiencies of around 70% to 90% are possible. Common feedstocks in biomass-fired CHP plants are forestry and agricultural residues, and the biogenic component of municipal residues and wastes. Sweden is the largest consumer of wood and wood waste for district heating, followed by Finland and the United States. Denmark, Germany and Sweden are the largest users of MSW for district heating.

Solar thermal collectors produce heat derived from solar radiation by heating a fluid circulated through a collector. Solar thermal panels producing low-temperature heat (less than 80°C) are a commercial technology. Rooftop solar thermal panels producing medium-temperature heat (up to 150°C) are still in the early stages of development, although some are available on the market. By the end of 2008, worldwide installed solar thermal (low- and medium-temperature) capacity totalled 152 GWth (Figure 11.8). Almost 90% of this capacity was in China (88 GWth), Europe (29 GWth) and OECD North America (16 GWth). 9. A detailed overview of the 450 Scenario across all energy sectors and technologies is presented in Chapter 13. An analysis of the costs and benefits of the scenario is presented in Chapter 14. 10. Traditional cookstoves are discussed in Chapter 8.

Geothermal Direct-use geothermal applications include mature technologies to provide heat for industrial processes, space conditioning, district networks, swimming pools, greenhouses and aquaculture ponds. In Iceland, where there are favourable geologic conditions and efficient hot water distribution networks, 88% of all households use geothermal (produced mostly in CHP plants). Other OECD countries using geothermal for district heating are Germany, Austria, Denmark, Hungary, Slovakia and Belgium.

Heat pumps provide a highly efficient means of cooling, and space and water heating (IEA, 2010a). They upgrade low-temperature heat, available in ambient energy sources (air, water or ground), to useful higher temperature heat that can be used for low-temperature heating systems (e.g. water temperatures of up to 45°C for under-floor heating). In specific applications, heat pumps can also be used to provide domestic hot water, usually in combination with a relatively high-temperature heat source, such as exhaust air. Heat pumps are most commonly powered by electricity. As a result, the energy output of heat pumps has a renewable energy component (the ambient energy source) and a fossil-fuel component (from the electricity requirements). Heat pumps are not included in IEA renewable energy statistics. In this report, they are modelled as energy-efficiency improvements rather than renewables. Globally, there were some three million ground-source heat pumps installed at the beginning of 2010, using around 5 Mtoe of geothermal energy (IEA 2010b). About one-quarter of these are in the European Union, mainly in Sweden, Germany and France (EurObserv’ER, 2009).

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11

Policies to support renewables for heat Policy support for renewables for heat is low compared with renewables-based electricity or biofuels for transport. Most renewables for heat policies have focused on solar technologies. Moreover, the policies in place have not been very effective (IEA, 2008). The stop-and-go nature of support to renewable heat in some countries has inhibited growth. In the Netherlands, for example, a capital-cost subsidy for solar thermal systems was introduced in 1988 (and subsequently adjusted in 1992, 1995, 1997 and 2000), but ended in 2003. A subsidy scheme was reintroduced in 2009. In some cases, production of heat from renewable energy increased faster in countries without incentives. In the United States, the Energy Policy Act of 2005 established a 30% federal tax credit (up to $2 000) for the purchase and installation of residential solar water heating. Initially scheduled to expire at the end of 2007, the tax credit was extended in 2008 until December 31, 2016. Under the National Climate Change Plan (2008), Brazil plans to increase the sustainable use of charcoal in the iron and steel industry, primarily by the support of forestation in degraded areas. Brazil’s plan also includes an incentive to encourage the use of solar water heating, aimed at reducing electricity consumption by 2 200 gigawatt-hours (GWh) per year by 2015. South Africa has targets for the use of solar water heaters in its Renewable Energy Framework. In 2007, the government of Shandong Province in China created a fund to support solar hot water supply systems in hotels, schools and other establishments. Other examples of policies to support renewables-based heat are found mainly in the European Union and Australia (Table 11.3).

Notes: Table does not include capital-cost subsidies, which are nearly ubiquitous in European Union countries. In September 2010, the United Kingdom’s Committee on Climate Change, which advises the government, suggested that the proposed target in the Renewable Heat Incentive (from around 1.6% in 2009 to 12% in 2020) may be too costly to achieve, and that a slightly lower level of ambition for heat may be appropriate.

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Box 11.5 z Renewable heat obligations and feed-in tariffs in the European Union Recently, more renewable heat policies have had a regulatory component, while still drawing on the experience of successful support mechanisms for renewable electricity policies. The Spanish government developed a national solar obligation policy in 2006. Since a solar obligation incentivises one specific technology, such a policy should be introduced only where there is no competition with other renewable technologies for the same market. The procedure for checking compliance and the absence of an incentive to exceed the required level of the obligation are weaknesses of the solar obligation. Another regulatory approach consists of requiring a defined share of a building’s heat to be supplied by renewable energy, such as in the London “Merton Rule” (Table 11.3) and the German 2009 building regulations. This type of obligation allows for competition between renewable (heating) technologies, but still lacks any incentive to exceed the required renewable share in heating demand which, in the case of the Merton Rule, is a modest 10% share. When applied to new buildings only, the effect, in many cases, will be limited, as annual construction rates in OECD countries are, on average, about 1% of the total building stock. In both of these examples, the regulation applies at the individual building level, discouraging more ambitious approaches.

The United Kingdom aims to introduce a Renewable Heat Incentive by April 2011, a first initiative in designing a feed-in tariff policy for the heat market. In Germany, the introduction of a renewable heat feed-in tariff policy has been explored, but the approach has been dropped in favour of an obligation policy (Bürger et al., 2008). Introducing a feed-in tariff scheme, as used for renewable electricity, to the renewable heat market gives rise to complications, due to key differences between the delivery of heat and electricity (Connor et al., 2009). The more heterogeneous nature of the fuels used for heat production and the relatively small scale of operation means that there is a far more diverse group of companies supplying the market. The mechanism must be designed to treat all supply companies equitably. A key problem in a renewable heating feed-in tariff scheme is assessing the generated heat output. Heat metering is costly relative to any available subsidy, suggesting that an alternative is needed. Moreover, as there generally is no “grid” to which excess domestic heat can be delivered, provisions must be included to avoid rewarding the production of unused heat.

In the European Union, a direct capital-cost subsidy to support for the purchase of renewable heating systems is the most widely adopted financial mechanism to support renewable heat technologies. In general, capital-cost subsidies are the most successful way to encourage higher penetration of renewable technologies when they are in the prototype and demonstration phase (IEA, 2008). Solar thermal technology continues to benefit from capital-cost subsidies in many countries, even though it is a relatively mature technology. Chapter 11 - Renewables for heat

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11

Capital-cost subsidies incur low transaction costs, especially if an administrative entity accustomed to handling subsidy schemes is already operational. They also appeal to consumers, who are used to paying a one-time upfront investment for heating or hot water installations. In the case of renewable heat, a considerable share of the market is expected to consist of consumers buying individual heating systems. The capital subsidy in many countries is provided upfront and there is no monitoring of compliance with installation guidelines.

Renewable energy for cooling Cooling is a service that meets demand for individual comfort and refrigeration in the buildings sector and process cooling in the industrial sector. Unlike heating, cooling demand is highly correlated to income. Energy-use data for cooling, however, are not collected. Electricity use in cooling systems, for example, is included in aggregated electricity use in the buildings and industry sectors. Renewable cooling technologies range widely, consisting of passive cooling, storing heat in the ground for extraction during winter, using renewable heat for cooling and using renewable power for cooling. During the warm season, passive cooling uses relatively constant low temperatures of deep seawater, deep lake water or the ground (ideally between 0°C and 10°C on average), to circulate a working fluid through floor heating pipes or to cool the air in large-scale air-conditioning systems. Cooling can be provided in combination with a ground source heat pump, where the (renewable) heat of the building is transported to the ground, perhaps to be stored in aquifers for extraction during winter. This technology has already proven to be commercially competitive with conventional cooling systems in large office buildings, commercial buildings, hospitals, housing, industry and agriculture.11 Cooling can also be provided in a district system where cold water is distributed through the network.

Solar-assisted cooling technologies match peak cooling demands with maximum solar radiation, and, hence with peak electricity loads for conventional air conditioners. The thermally-driven process in solar-assisted cooling is complex, being based on a thermochemical sorption process or a thermally-driven open cooling cycle. The technology has not been widely applied and needs more research and development to achieve competitive levels of reliability and cost with conventional cooling technologies. Another route is to generate electricity, for example using solar photovoltaics, to power a conventional refrigeration device.

z Biofuels demand is expected to increase rapidly over the projection period,

thanks to rising oil prices and government support, prompted by energy-security and environmental concerns. In the New Policies Scenario, global biofuels consumption increases from 1.1 mb/d today to 4.4 mb/d in 2035. Biofuels meet 8% of world road-transport fuel consumption by 2035, up from 3% in 2009. Over 2009-2035, biofuels meet about 20% of global incremental demand for total roadtransport fuels. In the 450 Scenario, biofuels account for 4% of the CO2 emissions reductions, compared with the New Policies Scenario. z The United States and Brazil are expected to remain the world’s largest producers

and consumers of biofuels. The United States accounts for 38% of total biofuels use by 2035 in the New Policies Scenario (down from 45% today), followed by Brazil with 20% (28% today). The share of non-OECD Asian countries, mainly China and India, increases most, from 6% in 2009 to 19% in 2035. Biofuels use in non-OECD Asia outstrips that in EU countries by the end of the projection period. z Today, almost all commercial biofuels production uses conventional technology.

Advanced biofuels, including those from ligno-cellulosic feedstocks, are assumed to enter the market by around 2020 in the New Policies Scenario, mostly in OECD countries. In that scenario, advanced biofuels account for 36% of biofuels use in OECD countries in 2035, but only 5% in non-OECD countries. z The projected expansion of biofuels supply in the New Policies Scenario requires

cumulative investment in production capacity of $335 billion over 2010-2035. More than half of this, some $180 billion, is for conventional production of ethanol, 10% for conventional biodiesel and the remainder for advanced biofuels. Around 60% of total investment is in OECD countries.

z Biofuels receive more government support than any other renewable energy

source or carrier. Total support in 2009 was $20 billion, with the highest levels in the United States and the European Union. The production of ethanol receives most of this, at $13 billion in 2009. Support is projected to average $45 billion per year between 2010 and 2020, further increasing to about $65 billion per year between 2021 and 2035, with some 60% of it directed at ethanol and 40% at biodiesel. Government support typically raises costs to motorists and to the economy as a whole. But the benefits can be significant too, including reduced imports of oil and reduced CO2 emissions — if biomass is used sustainably and the fossil fuels used to process the biomass is not excessive.

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Overview Biofuels, electricity and hydrogen are widely regarded as renewable forms of energy, competing for application in the transport sector. All are, strictly speaking, energy carriers rather than sources of energy; but, more important, the extent to which they are genuinely renewable is open to question (Box 12.1). This chapter concentrates on biofuels for transport, biomass — the feedstock for making biofuels — being unquestionably renewable when produced in a sustainable way. Global production of biofuels was 52 million tonnes of oil equivalent (Mtoe), or 1 112 thousand barrels per day (kb/d), in 2009 (Table 12.1). The United States and Brazil, the world’s largest producers, accounted for almost three-quarters of global production on an energy-adjusted basis.1 Ethanol accounted for about 75% of global production of biofuels for transport. Investment in biofuels was severely affected by the economic and financial crisis in 2008-2009, falling by over 60% compared with 2008 as a result of lower oil prices and a drop in demand for transport fuels, but is likely to recover over the next few years (see Chapter 9). Table 12.1 z World biofuels production, 2009 Ethanol

Despite rapid growth in their use over the past decade in some countries, biofuels accounted for only 3% of global road-transport fuel demand in 2009. Production in the United States has grown strongly over the past few years, almost 30% per year on average in 2002-2009, and the country overtook Brazil as the largest producer in 2005 (Figure 12.1). Production in the United States reached 503 kb/d in 2009, but the share of biofuels in road-transport fuel use was still only 3%. Brazil has the highest share of biofuels in its road-transport fuel mix, 20% in 2009. Currently, biofuels are used almost exclusively for road transport, but interest in the use of biofuels for aviation is growing (see Spotlight).

1. All biofuels-related volumetric data is presented on a gasoline- and diesel-equivalent basis in the entire chapter for better comparability with oil, unless specified otherwise.

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Box 12.1 z Renewable transport fuels The question as to which transport fuels can be deemed renewable is not straightforward. Transportation fuels are energy carriers, not energy sources, and so the question as to which fuels can be classified “renewable” depends on how they are produced. Despite questions about their sustainability, the fact that biofuels are produced from biomass, which is a renewable energy source, clearly means that they can be considered as at least partially renewable. Electricity and hydrogen, the two other transport fuels that might be considered renewable, can be produced through different processes and from many different feedstocks, including fossil fuels, nuclear power and renewables. Hydrogen can be produced from a variety of renewable energy sources, including solar thermal applications, electrolysis powered by renewable energy, or the gasification of biomass. But, over the Outlook period, hydrogen is expected to be produced mostly from fossil fuels (natural gas, for the most part). Electricity used in electric vehicles or in plug-in hybrids plays an important role in meeting transport energy demand in all three scenarios in this Outlook, especially in the 450 Scenario, in which the use of low-carbon electricity is essential to reaching climate goals (see Chapter 14). In turn, electric cars can help mitigate problems over the variable nature of renewable energy. At times of excess supply, they can act as a storage medium: with vehicle-to-grid systems, electric cars could feed electricity back to the grid when renewable electricity production is low. Total battery capacity of electric cars and plug-in hybrids in the 450 Scenario is about 20 terawatt-hours (TWh) by 2035. But electricity, like hydrogen, cannot be simply designated a renewable fuel. Even in the 450 Scenario, renewables account for only 45% of world electricity generation in 2035, i.e. the majority of electricity generation is fossil and nuclear. Consequently, this chapter focuses on biofuels that are derived from renewable energy sources and, in aggregate, have a much larger renewable energy component than either electricity or hydrogen in the New Policies Scenario.

Biofuels consumption trends Many countries have strengthened policies and measures, or introduced new ones, in recent years to encourage biofuels production and use, despite concerns about the environmental sustainability of biofuels and their associated greenhouse-gas emissions. The surge in oil prices up to 2008 also increased the attractiveness of investing in biofuels production. Oil prices are assumed to rise steadily in the Current and New Policies Scenarios, further boosting the role of biofuels over the projection period, particularly in the United States, the European Union and non-OECD Asia. New government measures also increase biofuels production and use in the New Policies and 450 Scenarios, partly driven by energy security and environmental concerns. In the New Policies Scenario, the global use of biofuels in 2035 is almost four times higher than in 2009. Biofuels expand slightly less rapidly in the Current Policies Scenario (as policies are assumed not to change). Their use grows fastest in the 450 Scenario — more than seven-fold between 2009 and 2035 — thanks to much stronger government measures. In that scenario, global biofuels consumption grows on average by about 8% per year over the Outlook period (Box 12.3), more than two percentage points faster than in the New Policies Scenario and mostly a result of increased use of advanced biofuels and sugar cane ethanol. Biofuels account for 4% of the carbon-dioxide (CO2) emissions reductions in the 450 Scenario, compared with the New Policies Scenario.

*World includes international aviation bunkers (not included in regional totals).

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Box 12.2 z Biofuels definitions There is a lot of discussion on the terminology and definitions used to classify biofuels. They are commonly referred to as “first-” or “second-generation biofuels”, but the distinction is unclear. The reason is that the same fuel might be classified as first- or as second-generation, depending on whether the determining criterion is the maturity of the technology, the greenhouse-gas emissions balance or the applied feedstock. This year’s Outlook classifies biofuels as “conventional” and “advanced” according to the technologies used to produce them and their respective maturity. Conventional biofuels include well-established technologies that are producing biofuels on a commercial scale today. These biofuels are commonly referred to as first-generation and include sugar cane ethanol, starch-based ethanol, biodiesel, Fatty Acid Methyl Esther (FAME) and Straight Vegetable Oil (SVO). Typical feedstocks used in these mature processes include sugar cane and sugar beet, starch-bearing grains, like corn and wheat, and oil crops, like canola and palm, and in some cases animal fats. Advanced biofuels, sometimes referred to as second- or third-generation biofuels comprise different conversion technologies that are currently in the research and development, pilot or demonstration phase. More specifically, this category includes emerging biofuel technologies, such as hydrogenated biodiesel, which is based on vegetable oil, as well as all those based on ligno-cellulosic biomass, such as cellulosic-ethanol, biomass-to-liquids (BTL) diesel and bio-derived synthetic natural gas (bio-SNG), among others. The category also includes novel biofuel technologies that are mostly in the research and development and pilot stage, such as algae-based biodiesel or butanol, as well as the conversion of sugar into diesel-type biofuels using micro-organisms (such as yeast). This definition differs from the one used for “Advanced Biofuels” in the US legislation, which is based on a minimum 50% life-cycle greenhouse-gas reduction and which, therefore, includes sugar cane ethanol.

In the New Policies Scenario, biofuels consumption rises from 1.1 million barrels per day (mb/d) in 2009 to 2.3 mb/d in 2020 and 4.4 mb/d in 2035. The United States continues to dominate global biofuels use over the projection period (Table 12.2). This projection is, nonetheless, subject to important uncertainties, notably with respect to the pace of development and deployment of advanced biofuels, which are assumed to become more commercially viable, and the controversial question of the sustainability of conventional biofuels.2

2. There are numerous international forums such as the IEA’s Implementing Agreement on Bioenergy, the Global Bioenergy Partnership (GBEP) or the Roundtable on Sustainable Biofuels (RSB) looking into developing criteria and indicators regarding the sustainability of biofuels.

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Box 12.3 z Renewables in transport in the 450 Scenario In the 450 Scenario, use of biofuels increases from 1.1 million barrels per day (mb/d) in 2009 to 8.1 mb/d in 2035, equivalent to 15% of all transport fuels on an energy-equivalent basis in that year. This compares with an increase in the use of electricity in transportation from about 270 terawatt-hours (TWh) in 2008 to some 1 500 TWh in 2035, or 4% of all transport fuels, resulting from a significant increase in the fleet of electric cars. Hydrogen use in transport remains marginal. The brisk expansion of biofuels in this scenario results mainly from the rapid market penetration of advanced biofuels and sugar cane ethanol, both of which can emit substantially lower levels of greenhouse gases than fossil fuels on a wellto-wheels basis (see the section on biofuels emissions), assuming that biomass is grown sustainably. Advanced biofuels account for around two-thirds of biofuels consumption by 2035 in the 450 Scenario.

The United States remains the dominant market throughout the projection period, accounting for 38% of global biofuels consumption in 2035. European consumption also grows strongly. The use of biofuels nearly triples in Latin America, from 0.35 mb/d in 2009 to 1 mb/d in 2035. Over the projection period, legal restrictions related to sustainability, such as those already introduced in the United States, are assumed to be introduced in the European Union, allowing blending targets to be met only with biofuels that substantially reduce greenhouse gases relative to fossil fuels. Consumption of biofuels in non-OECD Asia grows to about 800 kb/d in 2035, from only 62 kb/d in 2009, resulting principally from measures aimed at addressing concerns about oil-supply security and from the assumed phase-out of fossil-fuel subsidies (Figure 12.2). Growth in China accounts for nearly half of the increase in demand in this

mb/d

Figure 12.2 z Biofuels consumption by region in the New Policies Scenario 5

region, and India for one-third. While average annual growth hovers around 5% in more mature markets, such as the United States, Brazil and the EU countries, biofuels use grows by about 10% per year in China, albeit from a much lower base. Consequently, the share of non-OECD Asia in global demand increases from 6% in 2009 to 19% in 2035. Biofuels use in non-OECD Asia outstrips use in the European Union by the end of the projection period. Biofuels meet 8% of world road-transport fuel demand in 2035 in the New Policies Scenario. Brazil continues to rank highest in the share of biofuels in total road-fuel consumption, reaching more than 40% in 2035 (Figure 12.3). The share of ethanol in biofuels consumption remains high in all countries. Although biodiesel continues to dominate biofuels use in the European Union, the share of ethanol rises from 27% in 2009 to 31% in 2035 in EU biofuels consumption. Over 2009-2035, biofuels meet about 20% of global incremental growth in road-transport fuel demand, the result of policydriven increases in biofuels supply and demand-side efficiency measures to reduce oil consumption from road transport. Advanced biofuels, such as those produced from ligno-cellulosic feedstocks, are assumed to be commercialised by 2020 in the New Policies Scenario. By 2035, advanced biofuels account for some 36% of total biofuels demand in OECD countries. The costs of advanced biofuels decline faster than those of conventional biofuels, on the assumption that investment in research and development in advanced biofuel technologies increases significantly. The large biomass demand requirements for a commercial advanced biofuel plant of up to 600 000 tonnes per year require complex logistical systems and good infrastructure in order to deliver the biomass at an economically competitive cost. Successful production of advanced biofuels can, therefore, be a particular challenge in rural areas of developing countries, where poor infrastructure and a complex pattern of land-ownership in small land holdings increase the complexity of feedstock logistics. Consequently, in the New Policies Scenario, advanced biofuels meet only about 5% of biofuels demand at the end of the projection period in non-OECD countries, mostly in China and India. Figure 12.3 z Share of biofuels in total road-fuel consumption in selected regions by type in the New Policies Scenario Brazil United States European Union World

How green is your aircraft? Compared with the road transport sector, aviation has fewer options to replace conventional fuels. The energy density of jet fuel is critical for providing adequate aircraft flying range, so shifting to gaseous fuels or electricity is impractical in the short term. Liquid hydrogen would require major changes in aircraft design. Ethanol is not a suitable alternative source of energy, due to its relatively low energy content and weight: an aircraft would need to be entirely redesigned in order to be operated with ethanol-based biofuels. Jet fuel is a form of kerosene, not radically different from diesel fuel for road vehicles, so high-quality, high energy-density biodiesel is the closest substitute. But at normal cruising altitudes, low air temperatures lead to problems with FAME biodiesel gelling in the fuel lines and tanks (Biofuels International, 2010). The term bio-derived synthetic paraffinic kerosene (Bio-SPK) refers to those biofuels that are suitable for use as aviation biofuels and closely resemble conventional jet fuels. There are several promising technologies for making Bio-SPK from a variety of feedstocks and technology routes. Biomass-to-liquids (BTL) conversion of lignocellulosic feedstocks via Fischer-Tropsch synthesis is an interesting option for the medium term. Another option, which is very similar to conventional jet fuel and which has received considerable attention by airlines, is hydrogenated vegetable oil (HVO). Potential feedstocks are palm oil and waste vegetable oil, jatropha and camelina. Jatropha is a plant that can be grown in various soil conditions, including many that are not suitable for traditional agriculture, even though commercially attractive yields cannot be achieved on marginal land and cultivation is difficult. Camelina has similar characteristics to jatropha and is typically grown in temperate climates. Like jatropha, it is a crop that contains a lot of lipid, which can be extracted and converted to biofuels for aviation use. It is unclear as yet whether camelina offers any advantages over established crops (Schlumberger, 2010).

Algae are considered another promising feedstock for the large-scale production of biofuels for aviation. Algae are microscopic plants that grow suspended in water, undergoing a photosynthesis process that converts water, CO2 and sunlight into oxygen and biomass. However, there is still uncertainty about the economics of algae-based biofuels and the availability of suitable locations to produce larger volumes. Considerable research and development needs to be carried out before algae can be commercialised. The airline industry has shown great interest in testing and demonstrating the feasibility of using alternative fuels. A new aviation fuel specification, which will facilitate the use of alternative fuels, has been passed by the American Society for Testing and Materials (ASTM) International, the organisation which oversees international standards and specifications for jet fuel. Air New Zealand, Japan Airlines and Continental Airlines have carried out successful test flights using a blend of jatropha and traditional jet fuel. In 2009, Air France-KLM became the first airline to test biofuel in a passenger aircraft. The airline aims undertake to commercial flights that use biofuel from 2011.

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S P O T L I G H T

Lufthansa announced that, in 2012, it will start running engines on some flights on a mixture of biofuel and kerosene. British Airways recently announced plans to build an organic waste BTL plant near London. The US Air Force has also undertaken extensive research on aviation biofuels. Over the Outlook period, biofuels are expected to start to be regularly used for aviation by around 2020. But the pace of market growth is expected to depend on the vigour of government intervention.

In the New Policies Scenario, projected consumption calls for cumulative investment in biofuels production capacity of $335 billion (in year-2009 dollars) over the projection period (Figure 12.4). More than half of this investment, or about $180 billion, is for conventional production of ethanol, 10% for conventional biodiesel and the remainder for advanced biofuels. Around 60% of the total is invested in OECD countries. Over 50% of that investment goes to advanced biofuels technologies. Investment of more than $120 billion is required in non-OECD countries, nearly all of it in China and Brazil. Figure 12.4 z Cumulative investment in biofuel production facilities in the New Policies Scenario by technology, 2010-2035 (in year-2009 dollars)

In general, with rapid technological progress, financing the construction of advanced biofuels plants should not be particularly difficult in countries like Brazil, China, India, South Africa and Thailand, since it will generally be possible to attract foreign direct investment in addition to domestic funding. However, for less-developed countries, the sheer scale of the investment needs could be a barrier for biofuels, as for other energy investments, since domestic funding possibilities are limited and significant administrative and governance risks may deter foreign companies from undertaking large investments (IEA, 2009a). Chapter 12 - Renewables for transport

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Government policies to support biofuels In many countries, the biofuels industry depends heavily on government intervention, primarily in the form of obligations to blend biofuels into conventional fuels (blending mandates), production subsidies or both (Table 12.3). In such countries, these measures will continue to drive the expansion of biofuel production where it is otherwise not competitive with oil-based fuel production. Until recently, many biofuels programmes were conceived as part of farm-support policies, but a growing number of governments is now expanding or introducing such programmes for energy-security, economic and environmental reasons. Biofuels targets in the European Union, for example, can be seen as part of its commitment to reducing overall greenhouse-gas emissions. Table 12.3 z Current government support measures for biofuels in selected countries Targets/mandates* E5 (2010) B7 (2010) Australia (New South E6 (2011) Wales) B2 Brazil B5 (2010); E20-25 Canada E5 (2010) B2 (2012) China (nine provinces) E10 Colombia E10; B10 (2010); B20 (2012) France 7% by energy content Argentina

* Share of biofuels in total road-fuel consumption by volume (unless otherwise specified); E = Ethanol, and E5 represents a 5% share of ethanol in the final product fuel mix, similarly B = Biodiesel, and B7 represents a 7% share of biodiesel. Policies written in blue are mandatory. ** Use of corn as a feedstock is prohibited. Source: IEA databases and analysis.

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United States Under the Energy Independence and Security Act of 2007, the Renewable Fuel Standard (RFS) in the United States requires that 9 billion gallons of renewable fuels (34 billion litres) are to be consumed annually by 2008, rising progressively to 36 billion gallons (136 billion litres) by 2022. The Act specifies that 21 billion gallons of the 2022 target must be advanced biofuels, defined as fuels that, on a life-cycle basis, must emit 50% less greenhouse gases than the gasoline or diesel fuel it replaces. The US Environmental Protection Agency (EPA) is investigating the possibility of approving a 15% blend, up from a maximum of 10% today (Box 12.4).

Box 12.4 z Raising ethanol blend levels in the United States In the United States, legislation allows for ethanol blends to gasoline of up to 10% (E10), but not beyond. This 10% “blend wall” is seen by many as consistent with the technical limit on how much ethanol can be blended into gasoline without causing problems for conventional vehicles; but it represents a major barrier to achieving biofuels targets. This issue is controversial. Extensive testing is being undertaken, with a view to allowing higher blend shares. The Environmental Protection Agency (EPA) decided in October 2010 to allow an increase in the blend rate of ethanol in gasoline to 15% from 10% for cars and light trucks built since 2007. Vehicles sold between 2001 and 2006 are subject to further testing. The problem is how to impose a volumetric obligation — almost 140 billion litres (Table 12.3) — on a market which may be unable to absorb it. Who is to carry the risk? Farmers and ethanol producers would be delighted to see the required volumes, but fear that the market will be over-supplied and the obligation will fade away, leaving them exposed. The manufacturers have already suffered widespread bankruptcies, as prices for corn, the main feedstock for ethanol production in the United States, spiked in 2009. They are, therefore, pushing for approval of the use of E15 in older cars. Car manufacturers, however, fear they could be sued if owners of older cars buy fuel not suitable for their vehicles.

European Union The Renewable Energy Directive 2009/28/EC mandates a share of renewable energy in total transport demand in EU member countries of at least 10% by 2020. This directive requires that, from the end of 2010, biofuels must generate greenhouse-gas emissions savings of at least 35%, compared with fossil fuels, if they are to count towards the renewables target; these savings rise to 50% in 2017 and 60% in 2018. The current EU interpretation of this policy classifies rapeseed biodiesel, which accounts for most European production, as meeting the 35% threshold; soyabean and palm-based biodiesel, primary sources for imports, fall below it. Although actual soya and palm biodiesel production may bring about higher emissions savings, this depends critically on the production process: emission savings are often well below 35%. Moreover, Chapter 12 - Renewables for transport

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the challenge for foreign and domestic producers is likely to increase when indirect changes in land use are taken into account. The European Commission has recently funded several studies of indirect land use changes due to the use of biofuels. One showed that if domestic conventional biofuels were to be used to meet more than half of the 10% renewable fuels target by 2020, emissions from the indirect change in land use would be significant without substantial improvements in agricultural productivity, and would increase considerably as the share of domestically produced conventional biofuels increased (IFPRI, 2010). Advanced biofuels would be needed to reduce these emissions. The Commission has not yet issued requirements relating to the sustainability of the crops grown for biofuels production: the criteria are expected to be promulgated in November 2010. Germany has already placed limits on the origin of biofuels, an initiative which could shape EU policy more widely (FO Lichts, 2010a). The present basic requirements are laid out in several different directives, such as Directive 1998/70, which includes the EU Low Carbon Fuel Standard, the Renewable Energy Directive and the Fuel Quality Directive.

Brazil Brazil is the world’s largest producer of ethanol from sugar cane. Brazil’s national ethanol programme, ProAlcool, was launched in response to the oil crises in the 1970s. Lead in gasoline was phased out completely in 1991 and limits on carbon monoxide, unburned hydrocarbons and sulphur emissions were tightened, boosting the attractiveness of biofuels. In 2003, car manufacturers, beginning with Volkswagen, introduced “flex-fuel” vehicles (FFVs), which are capable of running on any combination of ethanol and gasoline. Such vehicles allow consumers to choose the cheapest fuel, whatever the type. These vehicles accounted for 40% of the car fleet in Brazil in 2009, compared with only about 4% in the United States.3 In Brazil, where ambient temperatures allow for higher blend shares than in the United States and the European Union, ethanol use is partly driven by mandatory ethanol blends and tax reductions for pure ethanol. From July 2007 to February 2010, the mandatory blend of ethanol in ethanol/gasoline blends was 25%. It was then reduced to 20% in an attempt to ease pressure on the sugar market, but was revised back up to 25% in May 2010. An obligation to blend 5% of biodiesel (B-5) into diesel fuels came into effect in January 2010.

Biofuels are generally not competitive with gasoline and diesel at market prices, so their production and use are encouraged by fiscal measures or other instruments. This year’s Outlook analyses biofuels support schemes in 20 countries,4 covering approximately 94% of total global biofuels consumption. The most common forms 3. There were some 8.3 million flex-fuel vehicles on the road in the United States in 2009. The number actually switching between the fuels is probably lower, however, as a recent survey in the United States found that 68% of E85 flex-fuel vehicle owners were not aware that they owned a flex-fuel vehicle. 4. United States, Germany, Spain, India, China, United Kingdom, Denmark, Portugal, France, Italy, Netherlands, Australia, Canada, Japan, Ireland, Greece, New Zealand, Austria, Brazil, Poland.

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of support are tax credits and tax exemptions, import tariffs on foreign biofuels and blending mandates. Blending mandates have played an increasing role in recent biofuel support policies, many countries adding blending mandates to existing fiscal incentives or entirely replacing fiscal incentives by mandates. Some, but not all, of these measures can be considered subsidies (see Chapter 19). In order to quantify the monetary value of government support to biofuels in this analysis, the tax advantage to biofuels, relative to the oil-based equivalent fuel, has been multiplied by the volume of biofuels consumed. Where blending mandates exist, tax reductions and biofuels prices were used for quantifying the implicit support through the blending mandate, which, in some cases is carried by the consumer (at least partially). Therefore, the value of what is called government support here represents a monetary value of all government interventions currently in place, irrespective of whether the cost is finally carried by the government or the consumer. Our analysis finds that biofuels worldwide receive more financial support than any other renewable technology (see Chapter 9). In 2009, global support for biofuels was almost as high as that for solar photovoltaics (PV) and wind combined, reaching $20 billion; this is compared with about $23 billion for solar PV and wind. Biofuels support increased by 40% in the two years to 2009. The production of ethanol received most of the support, roughly $9 billion in 2007, rising to more than $13 billion in 2009 (Figure 12.5).

Billion dollars (2009)

Figure 12.5 z Value of annual global government support to biofuels by type 25

The United States provide the highest level of support to biofuels. In 2009, the value of support for biofuels production — the bulk of total support directed at ethanol — reached $8.1 billion (Table 12.4). This was largely the result of a $0.45 per gallon excise tax credit and a blending mandate. EU support cost $7.9 billion in 2009, of which the largest share is taken by biodiesel in Germany. Support in Brazil, with the thirdlargest support programme, takes the form of tax credits on pure ethanol and blending mandates. China ranks fourth. Chapter 12 - Renewables for transport

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Table 12.4 z Value of government support to biofuels in selected countries (billion $) 2007

2008

2009

United States

4.9

6.6

8.1

Ethanol

4.6

6.2

7.7

Biodiesel

0.3

0.4

0.4

European Union

6.3

8.0

7.9

Ethanol

1.3

2.0

2.1

Biodiesel

5.0

6.0

5.8

2.3

2.5

2.6

2.3

2.5

2.6

Brazil Ethanol Biodiesel

0.0

0.0

0.1

0.3

0.6

0.5

Ethanol

0.2

0.5

0.4

Biodiesel

0.1

0.1

0.1

China

Government support to biofuels, as defined here, is not entirely paid for by governments. This is the case, for example, in Germany and the United States. The policy framework introduced in Germany in 2007 is something of a hybrid system, whereby only biofuel production above the level required by the national mandate attracts tax credits. In the case of biodiesel, Germany regularly far exceeded its own blending mandate between 2007 and 2009, with consumption reaching twice the level of the quota; as a result, the German government financed almost 55% of the cumulative $8.6 billion of support to biodiesel during those years, in the form of reduced tax revenues on road-transport fuel sales. The rest was paid by the consumer. For ethanol, the share of the government in total spending was lower, at about 20% between 2007 and 2009, as German ethanol consumption only slightly exceeded the mandate. In the United States, import tariffs on biofuels, in combination with blending mandates, increase the price of ethanol to consumers. Direct US government support takes the form of tax credits.

Brazil is a somewhat special case, as no pure gasoline is available to the consumer. Rather, Brazilian consumers can choose between pure ethanol or gasoline with a 25% ethanol blend (E25). Two types of regulations exist. One is a tax exemption on pure ethanol (hydrated ethanol), which, if compared with the tax on E25, accounted for $800 million of governmental support in 2007, increasing to $950 million in 2008 and $1 250 million in 2009. The rest is the impact of the blending mandate, where the ethanol part is taxed at a lower level than the gasoline part. According to Brazilian government officials, this difference in taxation does not represent a loss in tax revenues as taxes on the gasoline component have been increased to keep revenues constant. Government support has played an important role in facilitating the growth in biofuels supply in recent years and is likely to continue to do so over the Outlook period. To estimate the amount of support that would be required (in monetary terms) in the New Policies Scenario, biofuels prices have been calculated using biofuel conversion costs 368

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and efficiencies, and biomass feedstock prices, projected to 2035.5 These biofuels prices were then compared with gasoline and diesel prices before taxes by region over the projection period, and the increment was multiplied by the amount of biofuels consumed. Where biofuels prices break even with projected fossil-fuel costs over the projection period, such as in Brazil, support is assumed to be phased out. Using this approach, we calculate the average value of annual support for biofuels between 2010 and 2020 at $45 billion, increasing to about $65 billion between 2021 and 2035 (Figure 12.6). Ethanol absorbs most of the support, 60% on average, driven mainly by consumption in the United States. Biodiesel receives 40%, the European Union providing more support for biodiesel than other regions. Cumulatively, the support to biofuels in monetary terms is $1.5 trillion over the projection period.

Billion dollars (2009)

Figure 12.6 z Global average annual government support to biofuels in the New Policies Scenario 50

The cost of producing (or importing) biofuels is currently often significantly higher than the cost of imported oil. Consequently, government measures to encourage their production and use typically raise costs to motorists and the economy as a whole. There can be additional costs too, including the impact on food prices of devoting more land to biofuels production in the case of conventional biofuels. But the benefits can be large. These include a reduction in CO2 emissions (the overall savings vary enormously among the different types of biofuels, technologies and location), benefits to the agriculture sector, especially in developing countries, and the energy-security benefit of reduced imports of oil. All other things being equal, the use of biofuels at the levels of the New Policies Scenario results in a volumetric reduction of oil consumption between 2009 and 2035 sufficient to meet twice the total demand for oil in the OECD in the year 2035. 5. See (IEA Bioenergy, 2009) for biofuel conversion costs and efficiencies, and OECD (2010) for the biomass feedstock prices used in this analysis.

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Biofuels technologies Conventional biofuels Ethanol from sugar and starchy crops, and biodiesel from oilseed crops and animal fat, use well-established and simple conversion technologies. All current commercial biofuels production falls into these two categories. The main non-economic barriers to expanding the use of conventional biofuels are the demand for land and water, and the resulting competition with food and fibre production, as well as the threat to biodiversity. While these factors are potentially the same for any type of conventional biofuel, there are important differences according to the feedstock type and the region of production. Ethanol Ethanol is produced through a process of fermentation and distillation from sugar crops, such as sugar cane, sugar beet and sweet sorghum, or starch crops, such as corn, wheat and cassava. The basic production process from both types of crop is similar. But the energy requirement for the conversion of starch-based ethanol is much higher than that of sugar-based ethanol due to the additional process steps involved in converting starches into sugar. Ethanol can be used in blends of up to 10% in conventional spark ignition engines, or in blends of up to 100% in modified engines, although there is debate in many countries as to whether the 10% limit could be increased for newer vehicles. Though the energy content of ethanol is about two-thirds that of gasoline, when mixed with gasoline it has a higher octane rating, improves vehicle performance and can reduce CO2 emissions. Biodiesel Biodiesel is produced from vegetable oil and animal fat through a process known as esterification. Major feedstocks are rapeseed, soyabean, palm and sunflower, but about 11% of the feedstock is estimated to be animal fat and used cooking oil (FO Lichts, 2010b). The production process provides additional co-products, typically bean cake, animal feed and glycerine, which can be used in several industries. Biodiesel can be blended with diesel or used in pure form in compression ignition engines with little or no modification to the engine. Its energy content is only about 90-95% that of diesel, but the overall fuel economy of the two fuels is generally comparable and biodiesel raises the cetane level and improves lubricity.6 Biodiesel use can reduce emissions of CO2 and particulate matter from the vehicle, compared with pure diesel, though the overall picture is complex. The use of palm oil as the feedstock is particularly controversial as it can irreversibly damage the environment if not grown sustainably, resulting in very high life-cycle greenhouse-gas emissions.

Advanced biofuels In the production of conventional biofuels, only the starchy or sugary part of the plant is used for the production of fuel. These components represent a fairly small 6. The cetane number is a measurement of the combustion quality of diesel fuel during compression ignition. Lubricity is a measure of the reduction in friction of a lubricant.

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percentage of the total plant mass, leaving large quantities of fibrous remains, such as seed husks and stalks. Much current research is focused on innovative processes to use these materials, of which 20% to 45% by weight is cellulose, to create fermentable sugars. Successful conversion of such materials would make available a much broader range of biomass feedstocks. These include ligno-cellulosic feedstocks, such as wood, and agricultural residues such as straw, as well as perennial “woody” crops. When the conversion process is efficient, use of such residues and crops as feedstock can significantly reduce the area of land needed for growing crops for biofuels production, achieving higher biomass yields per hectare than biomass for many conventional biofuels. Other novel crops are being developed that may offer even higher productivity in the longer term. Production from cellulose is technologically challenging and the cost of enzymes to break down the cellulose feedstock into fermentable sugars is high. A good deal of progress has been made at the research level in various processes, including biochemical and thermal processes, but no commercial scale conversion facilities have, as yet, been built. One approach under development is to use a process similar to that used for coal-toliquid (CTL) and gas-to-liquid (GTL) fuels, i.e. gasification, combined with FischerTropsch (FT) synthesis (see Chapter 4). In this method, biomass must first be converted into a syngas through a two-step process involving thermal degradation of the biomass and cleaning of the derived gas. Then, FT synthesis is used to convert the syngas into biofuels. The products are of a similarly high quality to those derived from other fuelsynthesis processes. Biofuel-to-liquid (BTL)-diesel can be used in any given blend in conventional engines without modifications, which could be particularly interesting for the aviation industry. The BTL approach has advantages, such as reliance on non-food biomass.

Though no fully commercial conversion facilities have yet been built, developments in cellulosic ethanol and Fischer-Tropsch biodiesel are expected to drive the penetration of advanced biofuels in the New Policies Scenario and, more importantly, in the 450 Scenario. Demonstration projects have been successfully undertaken, such as DONG Energy’s 5 million litres per year (Ml/year) straw-fed cellulosic ethanol plant in Denmark. POET, a large ethanol producer in the United States, developing a 95 Ml/year plant, recently announced it had reduced cellulosic ethanol costs to only $1/gallon ($0.26/litre) higher than corn ethanol costs. Choren, a German company, completed a 17 Ml/year BTL plant in Germany in 2008, but it still has not commenced commercial production (IEA, 2010). Another interesting concept appears to be sugar-to-biodiesel conversion using yeast fermentation. AMYRIS, a US company, opened a pilot plant in California in 2008. Using bacteria for producing biodiesel from cellulosic materials is another concept under development by a research team of the US Joint BioEnergy Institute and the company LS9. This process might be able to produce a renewable fuel that can use existing distribution facilities. Chapter 12 - Renewables for transport

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12

Algae are now being intensively researched as a potential biofuel feedstock. In addition to their potentially high yields per unit land area, algae can grow in places unsuitable for agriculture, including industrial areas. Thus, their exploitation offers the prospect of a source of biofuel that avoids damage to ecosystems and competition with agriculture associated with other biomass resources. Although many testing and start-up companies are in operation in 12 countries, cost information is scarce. Biofuels from algae are, in any case, still at the research and development stage and face numerous obstacles related to energy and water needs, and productivity. A successful transition to advanced biofuels will depend on several factors:  Continuing strong public and private support for research and development, with

particular emphasis on developing the links between industry, universities and government.  Demonstration and pre-commercial testing, to reduce the risks to investors and

make participation attractive to financial institutions.  Development of widely-respected measures of performance, including life-cycle

assessment tools to assess the net effects on the energy balance and on greenhousegas emissions and the impacts on water and ecosystems.  Greater understanding of biomass resources through global mapping, in order

Biofuels emissions Biofuels are derived from renewable biomass feedstocks, but biofuels are not emissionfree on a life-cycle basis. There is keen debate about the level of emissions savings that can be attributed to the use of biofuels and, more generally, to biomass (see the spotlight in Chapter 9). Greenhouse-gas emissions can occur at any step of the biofuels supply chain.7 Besides emissions at the combustion stage, greenhouse-gas emissions arise from fossil-energy use in the construction and operation of the biofuels conversion plant. In addition, the cultivation of biomass requires fertilisers, the use of machinery and irrigation, all of which also generate emissions.

To quantify the net greenhouse-gas emission savings relative to petroleum-based fuels, it is necessary to calculate the extent to which total emissions are offset by the uptake of CO2 from the atmosphere during the growth of the biomass. If appropriate feedstocks and process conditions are chosen, biofuels can offer significant net 7. In IEA Statistics, biofuels (and biomass more generally) are not included in the data for CO2 emissions from fuel combustion. This is because CO2 emissions from biomass consumption for fuel production are assumed to be offset by CO2 savings through biomass re-growth. This methodology is in line with the 1996 IPCC Guidelines. Any departures from this assumption are counted within emissions from land use, land use change and forestry.

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greenhouse-gas emissions savings over conventional fossil fuels. This is particularly the case with sugar cane ethanol, as much less energy is required to convert the biomass to ethanol. But variations are large and calculating average emissions savings is complex (Figure 12.7). Expectations are high that advanced biofuels will be produced from ligno-cellulosic biomass and will offer excellent greenhouse-gas savings, using non-food crop feedstocks.

The greenhouse-gas benefits of biofuels use can be reduced or even become negative if emissions arising from the associated change of land use are significant.8 Such land use changes can be direct, as when feedstocks are grown on land that was previously forest or indirect, as when feedstock production for biofuels displaces other types of agricultural production undertaken on land elsewhere. So, for example, increasing the area dedicated to sugar cane or corn production for biofuels could displace cattle or soya production, which could lead to the conversion of forest land elsewhere for grazing cattle or producing soya. Such effects can be avoided when waste and residues are used as feedstock, or the feedstock is produced so as to give a higher yield per hectare or on land that is not otherwise used intensively to produce food or other products. Using land for biofuels production that was previously covered with carbon-rich forest or where the soil carbon content is high can release considerable amounts of greenhouse gases, and even lead to a “carbon debt”. In the worst cases, this debt could take hundreds or even thousands of years to recover via the savings in emissions 8. See, for example, UNEP (2009) and IEA Bioenergy (2009).

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by substituting biofuels for fossil fuels. However, establishing perennial energy plantations on land previously used to produce annual crops or on impoverished or under-productive lands can lead to improvements in carbon stocks and enhance the overall greenhouse-gas emissions savings. Indirect land-use changes are difficult to identify and model explicitly in greenhousegas balances. Several approaches are being developed to allow for such indirect effects. In some certification schemes (for example, the California Low-Carbon Fuel Standard), a specific greenhouse-gas penal